System and method for diffusion combustion with fuel-diluent mixing in a stoichiometric exhaust gas recirculation gas turbine system
Abstract
The system is equipped with a turbine combustor with a first diffusion fuel nozzle, the first diffusion fuel nozzle, respectively, in the chamber of the turbine combustor to generate a diffusion flame. Has first and second passages for injecting separately. The first stream contains a first fuel and a first diluent, and the second stream contains a first oxidant. The system includes a turbine driven by combustion products from a diffuse flame in a turbine combustor. The system also includes an exhaust gas compressor, which is configured to compress the exhaust gas and send it from the turbine to the turbine combustor along the exhaust gas recirculation path. [Selection diagram] Fig. 16

Term
Projected expiry 1 November 2033.
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162 claims: 17 independent, 145 dependent
- 1第1の流れが第1の燃料及び第1の希釈剤を含み、第2の流れが第1の酸化剤を含むそれぞれの第1及び第2の流れをタービン燃焼器のチャンバ内に別々に注入して拡散火炎を発生させる第1及び第2の通路を含む第1の拡散燃料ノズルを含むタービン燃焼器と、 前記タービン燃焼器における前記拡散火炎からの燃焼生成物によって駆動されるタービンと、 排気ガスを圧縮してそれを排気ガス再循環経路に沿って前記タービンから前記タービン燃焼器に送るように構成された排気ガス圧縮機と、を備えている、 ことを特徴とするシステム。
- 2前記第1の希釈剤は、前記排気ガスの一部、蒸気、窒素、別の不活性ガス、又はこれらの何れかの組み合わせを備えている、 請求項1に記載のシステム。
- 3前記第1の希釈剤は、前記排気ガスの一部を備えている、 請求項1に記載のシステム。
- 4前記第1の希釈剤は、蒸気を備えている、 請求項1に記載のシステム。
- 5前記第1の希釈剤は、不活性ガスを備えている、 請求項1に記載のシステム。
- 6前記不活性ガスは、窒素を備えている、 請求項5に記載のシステム。
- 7前記第1及び第2の通路は、前記第1の拡散燃料ノズルの下流端部に沿って配置されたそれぞれの第1及び第2の出口を有し、該第1及び第2の通路は、該第1の拡散燃料ノズルに沿って互いに隔離される、 請求項1に記載のシステム。
- 8前記第1及び第2の通路は、同心配列で配置される、 請求項1に記載のシステム。
- 9前記第1の通路は、前記第2の通路の周囲に延びる、 請求項1に記載のシステム。
- 10前記第2の通路は、前記第1の通路の周囲に延びる、 請求項1に記載のシステム。
- 11前記第1の拡散燃料ノズルは、前記第1及び第2の通路とは別個の第3の通路を備え、該第3の通路は、第3の流れを前記第1及び第2の流れとは別々に前記チャンバ内に注入するように構成され、該第3の流れは、第2の燃料、第2の希釈剤、又は第2の酸化剤を備えている、 請求項1に記載のシステム。
- 12前記第3の流れは、前記第2の燃料を含み、前記第1及び第2の燃料は、互いに同じである、 請求項11に記載のシステム。
- 13前記第3の流れは、前記第2の燃料を含み、前記第1及び第2の燃料は、互いに異なる、 請求項11に記載のシステム。
- 14前記第3の流れは、前記第2の燃料及び前記第2の希釈剤を含んでいる、 請求項11に記載のシステム。
- 15前記第1及び第2の燃料は、互いに同じであり、又は前記第1及び第2の希釈剤は、互いに同じであり、又はこれらの組み合わせである、 請求項14に記載のシステム。
- 16前記第1及び第2の燃料は、互いに異なり、又は前記第1及び第2の希釈剤は、互いに異なり、又はこれらの組み合わせである、 請求項14に記載のシステム。
- 17前記第1及び第2の燃料は、互いに異なり、かつ前記第1及び第2の希釈剤は、互いに同じであり、又は該第1及び第2の燃料は、互いに同じであり、かつ該第1及び第2の希釈剤は、互いに異なる、 請求項14に記載のシステム。
- 18前記第1及び第2の希釈剤は、前記排気ガスの一部を含んでいる、 請求項14に記載のシステム。
- 19前記第1の拡散燃料ノズルは、前記第1、第2、及び第3の通路とは別個の第4の通路を備え、 前記第4の通路は、前記第1、第2、及び第3の流れとは別個に第4の流れを前記チャンバ内に注入するように構成され、 前記第4の流れは、第3の燃料、第3の希釈剤、又は第3の酸化剤を含む、 請求項11に記載のシステム。
- 20前記タービン燃焼器は、第2の拡散燃料ノズルを備えている、 請求項1に記載のシステム。
- 21前記タービン燃焼器は、第1の予混合燃料ノズルを備えている、 請求項1に記載のシステム。
- 22前記タービン燃焼器は、前記第1の拡散燃料ノズルから下流側に配置された希釈剤注入システムを備えている、 請求項1に記載のシステム。
- 23前記希釈剤注入システムは、前記排気ガスの一部、蒸気、窒素、又は別の不活性ガス、又はこれらの組み合わせを前記第1の拡散燃料ノズルから下流側の前記タービン燃焼器の前記チャンバ内に注入するように構成される、 請求項22に記載のシステム。
- 24前記希釈剤注入システムは、前記タービン燃焼器のライナーに複数の開口部を備え、該複数の開口部は、該タービン燃焼器の前記チャンバ内に前記排気ガスの前記部分を注入するように構成される、 請求項23に記載のシステム。
- 25前記タービン燃焼器は、前記チャンバの周りに配置された第1の壁、該第1の壁の周りに配置された第2の壁、及び該第1及び第2の壁の間に配置された排気ガス通路を備え、 前記希釈剤注入システムは、前記タービン燃焼器の前記第1及び第2の壁を通って延びる複数の希釈剤注入器を含む、 請求項23に記載のシステム。
- 26前記複数の希釈剤注入器は、前記排気ガスの前記部分、蒸気、窒素、又は別の不活性ガスを前記タービン燃焼器の前記チャンバ内に注入するように構成される、 請求項25に記載のシステム。
- 27前記排気ガス再循環経路に沿って配置された第1の触媒ユニットを備えている、 請求項1に記載のシステム。
- 28前記第1の触媒ユニットは、前記排気ガス内の一酸化炭素、二酸化炭素、及び未燃炭化水素の濃度レベルを制御するように構成される、 請求項27に記載のシステム。
- 29前記第1の触媒ユニットは、酸化触媒、一酸化炭素触媒、アルミニウム酸化物、ジルコニウム酸化物、シリコーン酸化物、チタン酸化物、プラチナ酸化物、パラジウム酸化物、コバルト酸化物、又は混合金属酸化物、又はこれらの組み合わせを備えている、 請求項27に記載のシステム。
- 30前記酸化触媒ユニットは、前記排気ガス及び酸化剤燃料との酸化反応を駆動するように構成される、 請求項1に記載のシステム。
- 31前記酸化剤燃料の流れを調整して前記酸化反応を制御するように構成された制御システムを備えている、 請求項30に記載のシステム。
- 32前記制御システムは、センサフィードバックに応答して前記酸化剤燃料の前記流れを調整するように構成され、該センサフィードバックは、酸素、一酸化炭素、水素、窒素酸化物、未燃炭化水素、又はこれらのいずれかの組み合わせを示すガス組成フィードバックを備えている、 請求項31に記載のシステム。
- 33前記排気ガス再循環経路に沿って配置された第1の熱回収ユニットを備えている、 請求項1に記載のシステム。
- 34前記第1の触媒ユニットと前記第1の熱回収ユニットとを有する触媒及び熱回収システムを備えている、 請求項33に記載のシステム。
- 35前記第1の触媒ユニットは、前記第1の熱回収ユニットの上流側、下流側、又はこれと一体化されて配置される、 請求項33に記載のシステム。
- 36前記排気ガス再循環経路に沿って配置された第2の熱回収ユニットを備えている、 請求項33に記載のシステム。
- 37前記排気ガス再循環経路に沿って配置された第2の触媒ユニットを備えている、 請求項36に記載のシステム。
- 38前記第1の熱回収ユニットは、第1の熱回収蒸気発生器を備えている、 請求項33に記載のシステム。
- 39前記第1の熱回収蒸気発生器に結合された第1の蒸気タービンを備えている請求項38に記載のシステム。
- 40前記第1の熱回収ユニットは、第1の熱回収蒸気発生器を備え、前記第2の熱回収ユニットは、第2の熱回収蒸気発生器を備えている、 請求項36に記載のシステム。
- 41前記第1の熱回収蒸気発生器に結合された第1の蒸気タービンと、前記第2の熱回収蒸気発生器に結合された第2の蒸気タービンとを備えている、 請求項40に記載のシステム。
- 42前記排気ガス再循環経路に沿って配置された除湿システムを備えている、 請求項1に記載のシステム。
- 43前記除湿システムは、熱交換器、凝縮器、水ガス分離器、フィルタ、又はこれらのいずれかの組み合わせを備えている、 請求項42に記載のシステム。
- 44前記排気ガス再循環経路に沿って配置された粒子状物質除去システムを備えている、 請求項1に記載のシステム。
- 45前記粒子状物質除去システムは、慣性力選別装置、重力選別装置、フィルタ、又はこれらのいずれかの組み合わせを備えている、 請求項44に記載のシステム。
- 46前記排気ガス再循環経路に沿って配置されたブースタブロアを備えている、 請求項1に記載のシステム。
- 47前記排気ガス再循環経路に沿って配置された熱回収ユニット、ブースタブロア、除湿ユニット、及び粒子状物質除去ユニットを備えている、 請求項1に記載のシステム。
- 48前記排気ガスの一部を抽出するように構成された排気ガス抽出システムを備えている、 請求項1に記載のシステム。
- 49前記排気ガスの前記部分を処理するように構成された排気ガス処理システムを備えている、 請求項48に記載のシステム。
- 50前記排気ガス処理システムは、前記排気ガスの前記部分を分離して複数のガスストリームにするように構成されたガス分離システムを備えている、 請求項49に記載のシステム。
- 51前記複数のガスストリームは、二酸化炭素(CO 2 )リッチである第1のストリームと二酸化炭素(CO 2 )リーンである第2のストリームとを備えている、 請求項50に記載のシステム。
- 52前記第1のストリームは、窒素(N 2 )リーンであり、前記第2のストリームは、窒素(N 2 )リッチである、 請求項51に記載のシステム。
- 53前記排気ガス処理システムは、前記第1又は第2のストリームのうちの少なくとも一方を受け取るように構成されたガス圧縮システム、除湿システム、粒子状物質除去システム、又はこれらの組み合わせを備えている、 請求項51に記載のシステム。
- 54前記排気ガス処理システムは、前記複数のガスストリームのうちの少なくとも1つを精製するように構成されたガス精製システムを備えている、 請求項50に記載のシステム。
- 55前記複数のストリームのうちの少なくとも1つを受け取るように構成され、炭化水素生成システム、地下リザーバ、炭素隔離システム、パイプライン、貯蔵タンク、又はこれらのいずれかの組み合わせを含む目標システムを備えている、 請求項50に記載のシステム。
- 56前記排気ガス処理システムは、前記排気ガスの前記部分を圧縮するように構成された圧縮システムを備えている、 請求項49に記載のシステム。
- 57前記排気ガス処理システムは、除湿システム及び/又は粒子状物質除去システムを備えている、 請求項49に記載のシステム。
- 58センサフィードバックに応答して1又は2以上の作動パラメータを調整し、前記排気ガスの当量比又はエミッションレベルを制御する制御システムを備えている、 請求項1に記載のシステム。
- 59前記1又は2以上の作動パラメータは、前記タービン燃焼器への酸化剤流量及び/又は燃料流量を備えている、 請求項58に記載のシステム。
- 60前記制御システムは、約0.95と1.05の間の前記当量比を維持するように構成される、 請求項58に記載のシステム。
- 61前記センサフィードバックは、酸素、一酸化炭素、水素、窒素酸化物、未燃炭化水素、又はこれらのいずれかの組み合わせに関連するガス組成フィードバックを備えている、 請求項58に記載のシステム。
- 62前記制御システムは、前記センサフィードバックを得るように構成された複数のセンサに結合され、該複数のセンサは、前記排気ガス再循環経路、前記タービン燃焼器、前記タービン、前記排気ガス圧縮機、又はこれらの組み合わせに沿って配置される、 請求項58に記載のシステム。
- 63前記排気ガス圧縮機から前記タービンまでのバイパス管路を備え、 前記バイパス管路は、前記排気ガス圧縮機から前記タービンまでの前記排気ガスのバイパス流れを冷却するように構成された熱交換器を備えている、 請求項1に記載のシステム。
- 64前記タービン燃焼器と、前記タービンと、前記排気ガス圧縮機とを有するガスタービンエンジンを備え、 前記ガスタービンエンジンは、量論的排気ガス再循環(SEGR)ガスタービンエンジンである、 請求項1に記載のシステム。
- 65前記ガスタービンエンジンに結合された排気ガス抽出システムを備えている、 請求項64に記載のシステム。
- 66前記排気ガス抽出システムに結合された排気ガス処理システムを備えている、 請求項65に記載のシステム。
- 67前記排気ガス抽出システムに結合された炭化水素生成システムを備えている、 請求項65に記載のシステム。
- 68第1の流れが第1の燃料及び第1の希釈剤を含み、第2の流れが第1の酸化剤を含む第1及び第2の流れをタービン燃焼器のチャンバ内に別々に注入して拡散火炎を発生させる段階と、 前記拡散火炎からの燃焼生成物を用いてタービンを駆動する段階及び排気ガスを出力する段階と、 排気ガス再循環経路に沿って排気ガス圧縮機まで前記排気ガスを再循環させる段階と、 前記排気ガスを圧縮してそれを前記タービン燃焼器に送る段階と、を備えている、 ことを特徴とする方法。
- 69前記第1の希釈剤は、前記排気ガスの一部、蒸気、窒素、別の不活性ガス、又はこれらの何れかの組み合わせを備えている、 請求項68に記載の方法。
- 70前記第1の希釈剤は、前記排気ガスの一部を備えている、 請求項68に記載の方法。
- 71注入する段階は、第1の拡散燃料ノズルに沿って互いに隔離されたそれぞれの第1及び第2の通路から前記第1及び第2の流れを別々に注入する段階を有している、 請求項68に記載の方法。
- 72前記第1及び第2の通路は、同心配列で配置される、 請求項71に記載の方法。
- 73前記第1の通路は、前記第2の通路の周囲に延びる、 請求項71に記載の方法。
- 74前記第2の通路は、前記第1の通路の周囲に延びる、 請求項71に記載の方法。
- 75注入する段階は、第1の拡散燃料ノズルに沿って互いに隔離されたそれぞれの第1、第2、及び第3の通路から前記第1の流れ、前記第2の流れ、及び第3の流れを別々に注入する段階を有し、 前記第3の流れは、第2の燃料、第2の希釈剤、又は第2の酸化剤を含む、 請求項68に記載の方法。
- 76前記第3の流れは、前記第2の燃料を含み、前記第1及び第2の燃料は、互いに同じである、 請求項75に記載の方法。
- 77前記第3の流れは、前記第2の燃料を含み、前記第1及び第2の燃料は、互いに異なる、 請求項75に記載の方法。
- 78前記第3の流れは、前記第2の燃料及び前記第2の希釈剤を含む、 請求項75に記載の方法。
- 79前記第1及び第2の燃料は、互いに同じであり、又は前記第1及び第2の希釈剤は、互いに同じであり、又はこれらの組み合わせである、 請求項78に記載の方法。
- 80前記第1及び第2の燃料は、互いに異なり、又は前記第1及び第2の希釈剤は、互いに異なり、又はこれらの組み合わせである、 請求項78に記載の方法。
- 81前記第1及び第2の燃料は、互いに異なり、かつ前記第1及び第2の希釈剤は、互いに同じであり、又は該第1及び第2の燃料は、互いに同じであり、かつ該第1及び第2の希釈剤は、互いに異なる、 請求項78に記載の方法。
- 82前記第1及び第2の希釈剤は、前記排気ガスの一部を含んでいる、 請求項78に記載の方法。
- 83注入する段階は、第1の拡散燃料ノズルに沿って互いに隔離されたそれぞれの第1、第2、第3、及び第4の通路から前記第1の流れ、前記第2の流れ、第3の流れ、及び第4の流れを別々に注入する段階を有し、 前記第3の流れは、第2の燃料、第2の希釈剤、又は第2の酸化剤を含み、 前記第4の流れは、第3の燃料、第3の希釈剤、又は第3の酸化剤を含む、 請求項68に記載の方法。
- 84希釈剤の流れを前記第1の拡散燃料ノズルから下流側の前記チャンバ内に注入する段階を有している、 請求項71に記載の方法。
- 85前記排気ガスの一部を含む前記希釈剤の流れを前記タービン燃焼器のライナー内の複数の開口部を通して注入する段階を有している、 請求項84に記載の方法。
- 86前記排気ガスの一部、蒸気、窒素、又は別の不活性ガスを含む前記希釈剤の流れを前記タービン燃焼器の少なくとも1つの壁を通って延びる複数の希釈剤注入器を通して注入する段階を有している、 請求項84に記載の方法。
- 87前記排気ガス再循環経路に沿って第1の触媒ユニットを用いて前記排気ガスを処理する段階を有している、 請求項68に記載の方法。
- 88処理する段階は、前記排気ガス内の一酸化炭素、二酸化炭素、及び未燃炭化水素の濃度レベルを制御する段階を有している、 請求項87に記載の方法。
- 89処理する段階は、前記排気ガス及び酸化剤燃料による酸化反応を駆動する段階を有している、 請求項87に記載の方法。
- 90前記酸化反応を制御するために前記第1の触媒ユニットへの前記酸化剤燃料の流れを制御する段階を有している、 請求項89に記載の方法。
- 91酸素、一酸化炭素、水素、窒素酸化物、未燃炭化水素、又はこれらのいずれかの組み合わせを示すガス組成フィードバックを含むセンサフィードバックに応答して前記酸化剤燃料の前記流れを制御する段階を有している、 請求項90に記載の方法。
- 92第1の熱回収ユニット、第2の熱回収ユニット、又はこれらの組み合わせを用いて前記排気ガス再循環経路に沿って前記排気ガスから熱を回収する段階を有している、 請求項68に記載の方法。
- 93前記第1又は第2の熱回収ユニット内、上流側、又は下流側の第1の触媒ユニットを用いて第1の触媒反応を駆動する段階を有している、 請求項92に記載の方法。
- 94前記第1又は第2の熱回収ユニット内、上流側、又は下流側の第2の触媒ユニットを用いて第2の触媒反応を駆動する段階を有している、 請求項93に記載の方法。
- 95前記第1の熱回収ユニットの第1の熱回収蒸気発生器を用いて第1の蒸気を発生させる段階、前記第2の熱回収ユニットの第2の熱回収蒸気発生器を用いて第2の蒸気を発生させる段階、又はこれらの組み合わせを備えている、 請求項92に記載の方法。
- 96前記第1の蒸気を用いて第1の蒸気タービンを駆動する段階又は前記第2の蒸気を用いて第2の蒸気タービンを駆動する段階を有している、 請求項95に記載の方法。
- 97前記排気ガス再循環経路に沿って配置された除湿システムを用いて前記排気ガスから水分を除去する段階、又は該排気ガス再循環経路に沿って配置された粒子状物質除去システムを用いて該排気ガスから粒子状物質を除去する段階、又はその組み合わせを有している、 請求項68に記載の方法。
- 98前記除湿システムは、熱交換器、凝縮器、水ガス分離器、第1のフィルタ、又はこれらの何れかの組み合わせを備え、 前記粒子状物質除去システムは、慣性力選別装置、重力選別装置、第2のフィルタ、又はこれらの何れかの組み合わせを備えている、 請求項97に記載の方法。
- 99前記排気ガス再循環経路に沿って配置されたブースタブロアを用いて前記排気ガスの流れを強化する段階を有している、 請求項68に記載の方法。
- 100前記排気ガス再循環経路に沿って配置された熱回収ユニット、触媒ユニット、ブースタブロア、除湿ユニット、及び粒子状物質除去ユニットを用いて前記排気ガスを処理する段階を有している、 請求項68に記載の方法。
- 101排気ガス抽出システムを用いて前記排気ガスの一部を抽出する段階を有している、 請求項68に記載の方法。
- 102排気ガス処理システムを用いて前記排気ガスの前記部分を処理する段階を有している、 請求項101に記載の方法。
- 103前記排気ガスの前記部分を処理する段階は、該排気ガスの該部分を複数のガスストリームに分離する段階を有している、 請求項102に記載の方法。
- 104前記複数のガスストリームは、二酸化炭素(CO 2 )リッチである第1のストリームと二酸化炭素(CO 2 )リーンである第2のストリームとを備えている、 請求項103に記載の方法。
- 105前記排気ガスの前記部分を処理する段階は、ガス圧縮システムを用いて該排気ガスの該部分、前記第1のストリーム、又は前記第2のストリームを圧縮する段階を有している、 請求項104に記載の方法。
- 106前記排気ガスの前記部分を処理する段階は、除湿システムを用いて該排気ガスの該部分、前記第1のストリーム、又は前記第2のストリームから水分を除去する段階を有している、 請求項104に記載の方法。
- 107前記排気ガスの前記部分を処理する段階は、粒子状物質除去システムを用いて該排気ガスの該部分、前記第1のストリーム、又は前記第2のストリームから粒子状物質を除去する段階を有している、 請求項104に記載の方法。
- 108前記排気ガスの前記部分、前記第1のストリーム、又は前記第2のストリームを目標システムに送る段階を有し、 前記目標システムは、炭化水素生成システム、地下リザーバ、炭素隔離システム、パイプライン、貯蔵タンク、又はこれらのいずれかの組み合わせを備えている、 請求項104に記載の方法。
- 109センサフィードバックに応答して1又は2以上の作動パラメータを調整し、前記排気ガスの当量比又はエミッションレベルを制御する段階を有している、 請求項68に記載の方法。
- 110前記1又は2以上の作動パラメータを調整する段階は、前記タービン燃焼器への酸化剤流量及び/又は燃料流量を制御する段階を有している、 請求項109に記載の方法。
- 111前記1又は2以上の作動パラメータを調整する段階は、前記当量比を約0.95と1.05の間に維持する段階を有している、 請求項109に記載の方法。
- 112酸素、一酸化炭素、水素、窒素酸化物、未燃炭化水素、又はこれらのいずれかの組み合わせに関連する前記排気ガスのガス組成を監視することによって前記センサフィードバックを得る段階を有している、 請求項109に記載の方法。
- 113前記センサフィードバックを得る段階は、前記排気ガス再循環経路、前記タービン燃焼器、前記タービン、前記排気ガス圧縮機、又はこれらの組み合わせに沿って配置された複数のセンサを監視する段階を有している、 請求項112に記載の方法。
- 114前記排気ガス圧縮機から前記タービンまでバイパス管路に沿って前記排気ガスのバイパス流れを送る段階を有している、 請求項68に記載の方法。
- 115前記バイパス管路に沿って前記排気ガスの前記バイパス流れを冷却する段階と、該排気ガスの該バイパス流れを用いて前記タービンを冷却する段階とを備えている、 請求項114に記載の方法。
- 116前記タービン燃焼器と、前記タービンと、前記排気ガス圧縮機とを有するガスタービンエンジンを作動し、センサフィードバックに基づいて実質的に量論的な燃焼を達成する段階を有している、 請求項68に記載の方法。
- 117前記ガスタービンエンジンに結合された排気ガス抽出システムを用いて前記排気ガスの一部を抽出する段階と、該排気ガスの該部分を炭化水素生成システム、炭素隔離システム、パイプライン、貯蔵タンク、又はこれらのいずれかの組み合わせに送る段階とを有している、 請求項116に記載の方法。
- 118酸化剤を少なくとも1つの酸化剤圧縮機に導入して圧縮酸化剤ストリームを生成する段階と、 再循環された低酸素含有ガスストリームをガスタービンエンジンの圧縮機セクションに導入して圧縮低酸素含有ガスストリームを生成する段階と、 前記圧縮低酸素含有ガスストリームの第1の部分を燃料ストリームと混合する段階及び希釈燃料ストリームを生成する段階と、 実質的に化学量論比にある前記圧縮酸化剤ストリームの第1の部分及び前記希釈燃料ストリームを少なくとも1つのタービン燃焼器に導入する段階、燃焼ポイントにて該圧縮酸化剤ストリームの該第1の部分及び該希釈燃料ストリームを混合する段階、及び該圧縮酸化剤ストリームの該第1の部分及び該希釈燃料ストリームの該混合物を燃焼させる段階と、 前記圧縮低酸素含有ガスストリームの第2の部分を前記少なくとも1つのタービン燃焼器に導入する段階、前記燃焼ポイントの後でそれを前記圧縮酸化剤ストリームの前記第1の部分及び前記希釈燃料の前記燃焼ストリームと混合する段階、及び高温高圧低酸素含有ストリームを生成する段階と、 前記高温高圧低酸素含有ストリームを前記ガスタービンエンジンの膨張器セクションに導入する段階、及び該高温高圧低酸素含有ストリームを膨張させて機械出力及び再循環された低酸素含有ガスストリームを生成する段階と、 前記機械出力の第1の部分を使用して前記ガスタービンエンジンの前記圧縮機セクションを駆動する段階と、 前記機械出力の第2の部分を使用して発生器、前記少なくとも1つの酸化剤圧縮機、又は少なくとも1つの他の機械デバイスのうちの少なくとも1つを駆動する段階と、 前記ガスタービンエンジンの前記膨張器セクションの出口から前記圧縮機セクションの入口までの再循環ループで前記再循環された低酸素含有ガスストリームを再循環させる段階と、 前記ガスタービンエンジンから前記圧縮低酸素含有ガスストリームの少なくとも第3の部分を抽出する段階、該圧縮低酸素含有ガスストリームの該少なくとも第3の部分を前記第1の少なくとも1つの酸化触媒ユニットに送給する段階、及び低酸素含有生成物ストリームを生成する段階と、を有している、 ことを特徴とする方法。
- 119前記圧縮酸化剤ストリームの第2の部分を前記第1の少なくとも1つの酸化触媒ユニットに導入し、前記圧縮低酸素含有ガスストリームの前記第3の部分に含まれる一酸化炭素、水素、未燃炭化水素、又は不完全燃焼の類似の生成物のうちの少なくとも1つの少なくとも一部を酸化する段階を有している、 請求項118に記載の方法。
- 120酸化燃料を前記第1の少なくとも1つの酸化触媒ユニットに導入する段階、及び前記圧縮低酸素含有ガスストリームの前記第3の部分に含まれる残留酸素の少なくとも一部を還元する段階を有している、 請求項118に記載の方法。
- 121前記酸化剤は、本質的には周囲空気から成り、前記再循環された低酸素含有ガスストリームは、窒素を備えている、 請求項118に記載の方法。
- 122前記当量比(ファイ、φ)は、(モル%燃料/モル%酸化剤)実際/(モル%燃料/モル%酸化剤)化学量論に等しい、 請求項118に記載の方法。
- 123前記圧縮酸化剤ストリームの前記第1の部分及び前記燃料ストリームのうちの少なくとも一方の流量を制御して約1の燃焼当量比を達成し、該圧縮酸化剤ストリームの該第1の部分及び該燃料ストリームの実質的に化学量論の比を生成する段階を有している、 請求項122に記載の方法。
- 124前記再循環ループに設置され、かつ前記再循環された低酸素含有ストリーム内の成分を測定するセンサを備えている、 請求項123に記載の方法。
- 125前記測定される成分は、酸素、一酸化炭素、水素、窒素酸化物、及び未燃炭化水素のうちの少なくとも1つである、 請求項124に記載の方法。
- 126前記成分測定値を解析することによって前記当量比を決定する段階を有している、 請求項125に記載の方法。
- 127前記第1の少なくとも1つの酸化触媒ユニットの上流側、該第1の少なくとも1つの酸化触媒ユニットの下流側、又は両方に設置され、かつそこでの前記圧縮低酸素含有ガスストリームの前記抽出した第3の部分内の成分を測定する少なくとも1つのセンサを備えている、 請求項118に記載の方法。
- 128前記測定される成分は、酸素、一酸化炭素、水素、窒素酸化物、及び未燃炭化水素のうちの少なくとも1つである、 請求項127に記載の方法。
- 129前記燃焼当量比、前記圧縮酸化剤ストリームの前記第2の部分の流量、又は前記酸化燃料の流量のうちの少なくとも1つを調節し、かつ前記第1の少なくとも1つの酸化触媒ユニットの下流側で前記測定される成分のうちの少なくとも1つの望ましいレベルを達成する少なくとも1つのコントローラを備えている、 請求項128に記載の方法。
- 130前記第1の少なくとも1つの酸化触媒ユニットの下流側に第1の熱回収ユニットを備えている、 請求項118に記載の方法。
- 131前記第1の熱回収ユニットは、蒸気発生器を備えている、 請求項130に記載の方法。
- 132少なくとも1つの蒸気タービンに送給される蒸気を前記蒸気発生器によって生成する段階、及び電気出力を生成する発電機又は別の機械デバイスのうちの少なくとも一方を駆動する段階を有している、 請求項131に記載の方法。
- 133前記膨張器セクションの出口と前記ガスタービンエンジンの前記圧縮機セクションの入口との間の前記再循環ループにあり、かつ前記再循環された低酸素含有ガスストリームから熱を除去する第2の熱回収ユニットを備えている、 請求項118に記載の方法。
- 134前記第2の熱回収ユニットは、蒸気発生器を備えている、 請求項133に記載の方法。
- 135少なくとも1つの蒸気タービンに送給される蒸気を前記蒸気発生器によって生成し、かつ電気出力を生成する発電機又は別の機械デバイスのうちの少なくとも一方を駆動する段階を有している、 請求項134に記載の方法。
- 136前記圧縮低酸素含有ガスストリームの第4の部分を2次的流れとして前記ガスタービンエンジンの前記圧縮機セクションから前記タービンに送給し、かつ該タービンを冷却及び密封した後に該圧縮低酸素含有ガスストリームの該第4の部分を前記再循環ループの中に送給する二次流路を備えている、 請求項118に記載の方法。
- 137前記第2の熱回収ユニットの下流側で前記再循環された低酸素含有ガスストリームの圧力を増加させる前記再循環ループ内のブースタブロアを備えている、 請求項133に記載の方法。
- 138前記ガスタービンエンジンの前記圧縮機セクションの前記入口に流入する前に前記再循環された低酸素含有ガスストリームを冷却する熱交換器を該ガスタービンエンジンの該圧縮機セクションの上流側の前記再循環ループ内に備えている、 請求項133に記載の方法。
- 139前記熱交換器を用いて前記再循環された低酸素含有ガスストリームから水を凝縮して除去する段階を有している、 請求項138に記載の方法。
- 140炭化水素回収を高めるために前記低酸素含有生成物ストリームの少なくとも一部を地下リザーバに送給する段階を有している、 請求項118に記載の方法。
- 141炭化水素回収を高めるために前記低酸素含有生成物ストリームの前記少なくとも一部を地下リザーバに送給する前に少なくとも1つの不活性ガス生成物圧縮機を用いて該低酸素含有生成物ストリームの該少なくとも一部を圧縮する段階を有している、 請求項140に記載の方法。
- 142前記第1の熱回収ユニットによって前記低酸素含有生成物ストリームを冷却する段階を有している、 請求項141に記載の方法。
- 143前記低酸素含有生成物ストリームの前記少なくとも一部をガス脱水ユニットに送給する段階を有している、 請求項140に記載の方法。
- 144前記低酸素含有生成物ストリームの少なくとも一部を二酸化炭素分離ユニットに送給してリーン二酸化炭素ストリーム及びリッチ二酸化炭素ストリームを生成する段階を有している、 請求項118に記載の方法。
- 145炭化水素回収を高めるために前記リーン二酸化炭素ストリームの少なくとも一部を地下リザーバに送給する段階を有している、 請求項144に記載の方法。
- 146炭化水素回収を高めるために前記リッチ二酸化炭素ストリームの少なくとも一部を地下リザーバに送給する段階を有している、 請求項144に記載の方法。
- 147前記リッチ二酸化炭素ストリームの少なくとも一部を炭素隔離ユニットに送給する段階を有している、 請求項144に記載の方法。
- 148炭化水素回収を高めるために前記リーン二酸化炭素ストリームを地下リザーバに送給する前に該リーン二酸化炭素ストリームの前記少なくとも一部を少なくとも1つのリーン生成物圧縮機に対して圧縮する段階を有している、 請求項145に記載の方法。
- 149炭化水素回収を高めるために前記リッチ二酸化炭素ストリームを地下リザーバに送給する前に該リッチ二酸化炭素ストリームの前記少なくとも一部を少なくとも1つのリッチ生成物圧縮機に対して圧縮する段階を有している、 請求項146に記載の方法。
- 150前記リッチ二酸化炭素ストリームを炭素隔離ユニットに送給する前に該リッチ二酸化炭素ストリームの前記少なくとも一部を少なくとも1つのリッチ生成物圧縮機に対して圧縮する段階を有している、 請求項147に記載の方法。
- 151前記リーン二酸化炭素ストリームの少なくとも一部をガス脱水ユニットに送給する段階を有している、 請求項144に記載の方法。
- 152前記リッチ二酸化炭素ストリームの少なくとも一部をガス脱水ユニットに送給する段階を有している、 請求項144に記載の方法。
- 153前記低酸素含有生成物ストリームの少なくとも一部を膨張器に導入する段階、該低酸素含有生成物ストリームの該少なくとも一部を膨張させる段階、発電機又は別の機械デバイスのうちの少なくとも一方を駆動する段階、及びベントストリームを生成する段階を有している、 請求項118に記載の方法。
- 154前記リーン二酸化炭素ストリームの少なくとも一部を膨張器に導入する段階、該リーン二酸化炭素ストリームの該少なくとも一部を膨張させる段階、発電機又は別の機械デバイスのうちの少なくとも一方を駆動する段階、及びベントストリームを生成する段階を有している、 請求項144に記載の方法。
- 155前記再循環ループ内に位置付けられ、前記再循環された低酸素含有ガスストリームに含まれる一酸化炭素、水素、未燃炭化水素、又は不完全燃焼の類似の生成物のうちの前記少なくとも1つの少なくとも一部を酸化する第2の少なくとも1つの酸化触媒ユニットを備えている、 請求項118に記載の方法。
- 156前記第2の少なくとも1つの酸化触媒ユニットは、前記第2の熱回収ユニットの上流側に配置されている、 請求項155に記載の方法。
- 157前記第2の少なくとも1つの酸化触媒ユニットは、前記第2の熱回収ユニットの下流側に配置される、 請求項155に記載の方法。
- 158前記第2の少なくとも1つの酸化触媒ユニットは、適切な作動温度を提供しかつ前記触媒反応によって発生する熱に対して適切なヒートシンクを提供する場所で前記第2の熱回収ユニット内に配置される、 請求項155に記載の方法。
- 159前記圧縮低酸素含有ガスストリームの前記少なくとも第2の部分の流量を制御する段階を有している、 請求項118に記載の方法。
- 160前記圧縮低酸素含有ガスストリームの前記少なくとも第2の部分の前記流量は、前記再循環ループ内の場所での圧力を望ましい範囲内に維持するように調整される、 請求項159に記載の方法。
- 161前記圧縮低酸素含有ガスストリームの前記少なくとも第2の部分の前記流量は、抽出バルブ、抽出通気バルブ、生成物圧縮機作動速度、生成物圧縮機入口ガイドベーン位置、又は生成物圧縮機再利用バルブのうちの少なくとも1つによって調整される、 請求項159に記載の方法。
- 162前記熱交換器の下流側にあり、かつ前記凝縮した水の除去の有効性を改善する慣性力選別装置、凝集フィルタ、及び水不透過性フィルタのうちの少なくとも1つを備えている、 請求項139に記載の方法。
Independent claims162
262 paragraphs, as filed
0001[Cross-reference to related applications] This application is a US patent application No. 14/067,537, 2012, in which the name of the application on October 30, 2013 is "SYSTEM AND METHOD FOR DIFFUSION COMBUSTION WITH FUEL-DILUENT MIXING IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GAS TURBINE SYSTEM". US patent provisional application No. 61 / 722,118 with the name of the application on November 2, 2012 is "SYSTEM AND METHOD FOR DIFFUSION COMBUSTION IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GAS TURBINE SYSTEM", and the name of the application on November 2, 2012 is "SYSTEM AND". METHOD FOR DIFFUSION COMBUSTION WITH FUEL-DILUENT MIXING IN A STOICHIOMETRIC EXHAUST US Patent Provisional Application No. 61 / 722,115, which is "GAS RECIRCULATION GAS TURBINE SYSTEM", the name of the application on November 2, 2012 is "SYSTEM AND METHOD FOR DIFFUSION COMBUSTION WITH OXIDANT-DILUENT MIXING IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GAS TURBINE SYSTEM" US Patent Provisional Application No. 61 / 722,114, and the name of the application on November 2, 2012 is "SYSTEM AND METHOD FOR LOAD CONTROL WITH DIFFUSION COMBUSTION IN A STOICHIOMETRIC EXHAUST GAS RECIRCULATION GAS TURBINE SYSTEM". Claiming priority and interests to / 722,111, all of these patent applications are incorporated herein by reference in their entirety.
0002The subject matter disclosed herein relates to gas turbine engines.
<p num="0003"> Gas turbine engines are used in a wide variety of applications such as power generation, aircraft, and various mechanical devices. Gas turbine engines typically burn fuel with an oxidant (eg, air) in the combustor section to produce hot combustion products, which drive one or more turbine stages in the turbine section. The turbine section then drives one or more compressor stages of the compressor section, thereby compressing the oxidant for suction into the combustor section along with the fuel. Again, the fuel and oxidizer are mixed in the combustor section and then burned to produce a hot combustion product. Gas turbine engines generally premix fuel and oxidizer along one or more channels upstream from the combustion chamber of the compressor section, so gas turbine engines generally operate with a premixed flame. .. Unfortunately, controlling or maintaining a premixed flame can be difficult, which can affect various exhaust emissions and power requirements. In addition, gas turbine engines typically consume large amounts of air as oxidants and output significant amounts of exhaust gas into the atmosphere. In other words, the exhaust gas is typically wasted as a by-product of gas turbine engine operation.</p>
<p num="0004"> Certain embodiments within the scope of the invention, first described in the claims, are summarized below. These embodiments are not intended to limit the technical scope of the claimed invention, but rather these embodiments are intended only to provide a brief overview of the feasible embodiments of the invention. doing. As a matter of course, the present invention may include various embodiments that may be similar to or different from the embodiments described below.</p><p num="0005"> In a first embodiment, the system is provided with a turbine combustor having a first diffusion fuel nozzle, the first diffusion fuel nozzle, each in a turbine combustor chamber to generate a diffusion flame. It has first and second passages that inject the first and second streams separately. The first stream contains a first fuel and a first diluent, and the second stream contains a first oxidant. The system includes a turbine driven by combustion products from a diffusion flame in a turbine combustor. The system also includes an exhaust gas compressor, which is configured to compress the exhaust gas and send it from the turbine to the turbine combustor along the exhaust gas recirculation path.</p><p num="0006"> In a second embodiment, the method comprises injecting the first and second streams separately into the chamber of the turbine combustor to produce a diffuse flame, the first stream being the first. It contains a fuel and a first diluent, and a second stream contains a first oxidant. The method further includes a step of driving the turbine with combustion products from the diffusion flame and a step of outputting the exhaust gas. The method further comprises the step of recirculating the exhaust gas to the exhaust gas compressor along the exhaust gas recirculation path. The method further comprises the step of compressing the exhaust gas and sending it to the turbine combustor.</p><p num="0007"> In a third embodiment, the method comprises introducing an oxidant into at least one oxidant compressor to produce a compressed oxidant stream. The method further comprises introducing a recirculated hypoxic gas stream into the compressor section of the gas turbine engine to produce a compressed hypoxic gas stream. The method further comprises mixing a first portion of the compressed hypoxic containing gas stream with the fuel stream and producing a diluted fuel stream. The method substantially introduces the first portion of the compressed oxidant stream and the diluted fuel stream into at least one turbine combustor in terms of chemical ratio, and at the combustion point the first part of the compressed oxidant stream. It further comprises the step of mixing the portion and the diluted fuel stream and the step of burning the mixture of the first portion of the compressed oxidant stream and the diluted fuel stream. The method introduces a second portion of the compressed low oxygen-containing gas stream into at least one turbine combustor, and after the combustion point it is a combustion stream of the first portion of the compressed oxidizer and the diluted fuel. Further includes a step of mixing with and a step of producing a high temperature, high pressure and low oxygen containing stream. The method involves introducing a high temperature, high pressure, low oxygen content stream into the expander section of a gas turbine engine and expanding the high temperature, high pressure, low oxygen content stream to produce a mechanical output and a recirculated low oxygen content gas stream. And further include. The method further comprises the step of using the first portion of the mechanical power to drive the compressor section of the gas turbine engine. The method further comprises using a second portion of mechanical power to drive at least one of a generator, at least one oxidant compressor, or at least one other mechanical device. The method further comprises recirculating the recirculated low oxygen-containing gas stream in a recirculation loop from the outlet of the expander section of the gas turbine engine to the inlet of the compressor section. The method extracts at least a third portion of a compressed hypoxic gas stream from a gas turbine engine.</p><p num="0008"> These and other features, aspects and advantages of the present invention will be better understood by reading the following detailed description with reference to the accompanying drawings in which the same reference numerals represent similar parts throughout the drawings. Let's go.</p>
0009<figref num="1">FIG. 6 is a schematic representation of an embodiment of a system having a turbine-based service system coupled to a hydrocarbon production system.</figref><figref num="2">It is the schematic of one embodiment of the system of FIG. 1 which further shows the control system and the combined cycle system.</figref><figref num="3">FIG. 5 is a schematic diagram of one embodiment of the systems of FIGS. 1 and 2, further showing details of a gas turbine engine, an exhaust gas supply system, and an exhaust gas treatment system.</figref><figref num="4">It is a flowchart of one embodiment of the process of operating the system of FIGS. 1 to 3.</figref><figref num="5">It is the schematic of one embodiment of the exhaust gas treatment system of the system of FIGS. 1 to 3.</figref><figref num="6">It is the schematic of one embodiment of the exhaust gas supply system of FIGS. 1 to 3.</figref><figref num="7">It is a schematic diagram of one embodiment of the gas turbine engine of FIGS. 1 to 3 which further shows the details of the flow of the combustor, the fuel nozzle, and the oxidizer, fuel, and diluent.</figref><figref num="8">It is the schematic of one embodiment of the fuel nozzle of FIG. 7 which shows the premixed fuel nozzle configuration.</figref><figref num="9">It is the schematic of one embodiment of the fuel nozzle of FIG. 7 which shows the premixed fuel nozzle configuration.</figref><figref num="10">It is the schematic of one embodiment of the fuel nozzle of FIG. 7 which shows the premixed fuel nozzle configuration.</figref><figref num="11">It is a schematic diagram of one embodiment of the fuel nozzle of FIG. 7 which shows the diffusion fuel nozzle configuration.</figref><figref num="12">It is a schematic diagram of one embodiment of the fuel nozzle of FIG. 7 which shows the diffusion fuel nozzle configuration.</figref><figref num="13">It is a schematic diagram of one embodiment of the fuel nozzle of FIG. 7 which shows the diffusion fuel nozzle configuration.</figref><figref num="14">FIG. 3 is a schematic cross-sectional view of one embodiment of the fuel nozzle of FIG. 13 along lines 14-14.</figref><figref num="15">FIG. 3 is a schematic cross-sectional view of one embodiment of the fuel nozzle of FIG. 13 along lines 14-14.</figref><figref num="16">It is a schematic diagram of one embodiment of the combustor and the fuel nozzle of FIG. 7 showing a diffusion fuel nozzle configuration and a dilution injection system.</figref><figref num="17">FIG. 6 is a schematic cross-sectional view of one embodiment of the combustor and fuel nozzle of FIG. 7 along lines 17-17 showing a multi-nozzle configuration of fuel nozzles.</figref><figref num="18">It is a graph of a gas turbine load and an exhaust gas recirculation (EGR) flow-to-fuel / oxidant ratio for a diffuse flame configuration and a premixed flame configuration.</figref>
0010One or more specific embodiments of the present invention will be described below. As part of an effort to provide a brief description of these embodiments, this specification may not describe all features of the actual embodiment. As with any technology or design project, in the development of any actual implementation such as this, the specific goals of the developer that may vary from implementation to implementation, such as compliance with system and business related constraints. It should be understood that a number of implementation-specific decisions need to be made to achieve this. Moreover, such development efforts, which can be complex and time-consuming, are routine tasks of design, manufacture, and manufacturing for those skilled in the art who have the advantages of the present disclosure. I want you to understand.
0011In introducing the elements of the various embodiments of the invention, the singular description shall mean that one or more of the elements are present. The terms "provide," "include," and "have" are comprehensive and mean that additional elements other than those described may exist.
0012As discussed in detail below, the disclosed embodiments generally relate to gas turbine systems with exhaust gas recirculation (EGR), and more specifically, the amount of gas turbine systems with EGR. Regarding theoretical operation. For example, a gas turbine system recirculates exhaust gas along an exhaust gas recirculation path, quantitatively burning fuel and oxidants with at least a portion of the recirculated exhaust gas, and various target systems. It can be configured to take in exhaust gas for use in. Recirculating the exhaust gas with stoichiometric combustion is the carbon dioxide (CO) in the exhaust gas.<sub>2</sub>) Helps increase concentration levels and CO for use in various target systems<sub>2</sub>And nitrogen (N<sub>2</sub>) Can be post-treated for separation and purification. Gas turbine systems also utilize a variety of exhaust gas processes (eg, heat recovery, catalytic reactions, etc.) along the exhaust gas recirculation path, thereby CO.<sub>2</sub>Increases the concentration level of and lowers the concentration level of other emissions (eg, carbon monoxide, nitrogen oxides, oxygen, and unburned hydrocarbons) and improves energy recovery (eg, using a heat recovery unit). Can be made to. In addition, gas turbine engines can be configured to burn fuel and oxidants with one or more diffuse flames rather than or in addition to the premixed flames. Diffuse flames can help maintain stability and operation within certain limits against stoichiometric combustion, which in turn is CO.<sub>2</sub>Helps to increase the production of. For example, as described below, a gas turbine system operating on a diffuse flame can enable a larger amount of EGR than a gas turbine system operating on a premixed flame. Then, by increasing the amount of EGR, CO<sub>2</sub>Helps increase generation. Possible target systems include pipelines such as Enhanced Oil Recovery (EOR) systems, storage tanks, carbon sequestration, and hydrocarbon production systems.
0013As a general situation, it is worth considering the difference between a premixed flame (ie, premixed combustion) vs. a diffuse flame (ie, diffuse combustion). Combustion (ie, premixing or diffusion combustion) is essentially an exothermic chemical reaction between a fuel such as air, oxygen, oxygen enriched air, oxygen-deficient air, or a mixture of oxygen and nitrogen and an oxidant. (For example, combustion reaction). The exothermic chemical reaction between the fuel and the oxidant can substantially affect (and control) the stability of the flame (eg, the stability of the flame surface) and vice versa. For example, the release of heat from an exothermic chemical reaction helps sustain the flame, so higher flame temperatures generally lead to greater flame stability. In other words, higher temperatures associated with exothermic chemistries may help improve flame stability, whereas lower temperatures associated with exothermic chemistries may reduce flame stability. is there. The flame temperature may be largely determined by the fuel / oxidant ratio. In particular, the flame temperature can be maximized in the stoichiometric fuel / oxidizer ratio , which generally consumes substantially all of the fuel and oxidizer, as discussed in detail below. It involves an exothermic chemical reaction, which substantially does not result in residual oxidizer or unburned fuel.
0014By premixed combustion, the fuel and oxidizer are mixed at one or more locations upstream from the premixed flame, which is essentially the combustion of this premixed fuel and oxidant. In general, the exothermic chemical reaction of fuel and oxidizer in the premixed flame is constrained by the premixed fuel / oxidant ratio, which is achieved upstream from the premixed flame. In many configurations (especially when premixing one or more diluents with fuel and oxidizer), it becomes more difficult to maintain a substantially stoichiometric fuel / oxidant ratio in the premixed flame. It is possible and therefore it can be more difficult to maximize the stability of the flame. In certain configurations, premixed flames can be achieved with a fuel lean fuel / oxidant ratio, which lowers the flame temperature and thus nitrogen oxides (NO).<sub>X</sub>), For example, nitric oxide (NO) and nitrogen dioxide (NO)<sub>2</sub>) Helps reduce emissions. Reduced NO<sub>X</sub>Emissions are related to emission regulations, but reduced flame temperatures also cause reduced flame stability. Control emissions (eg NO) in the disclosed embodiments.<sub>X</sub>Controlling the system, using one or more diluents to reduce the temperature for the purpose of reducing emissions), a substantially stoichiometric fuel / oxidant ratio (eg, flame temperature). And to improve flame stability). In particular, the diluent is provided separately from the fuel and oxidizer (eg, after the combustion point and / or downstream from the premixed flame), as discussed below, thereby providing the diluent. Use temperature and emissions (eg NO<sub>X</sub>Stoichiometric combustion can be achieved by allowing more precise control of the fuel / oxidant ratio while controlling emissions). In other words, the fuel and oxidant flow as well as the diluent flow are controlled independently of each other, which allows for a more precisely controlled fuel / oxidant ratio to the premix delivered to the location of the premix flame. I will provide a.
0015Due to diffusion combustion, the fuel and oxidizer generally do not mix upstream from the diffusion flame, but rather the fuel and oxidizer mix and react directly on the flame surface and / or the flame surface is the fuel and oxidizer. It exists in a place where it mixes with. Specifically, the fuel and oxidizer are on the flame surface (or diffusion boundary / interface). And then diffuse along the flame surface (or diffusion boundary / interface) to generate a diffuse flame (eg, via molecular and viscous diffusion). It should be noted that the fuel and oxidizer can be substantially stoichiometric along this flame surface (or diffusion boundary / interface) and, as a result, along this flame surface. Higher flame temperatures (eg, peak flame temperatures) can be produced. Again, the stoichiometric fuel / oxidant ratio generally results in a higher flame temperature (eg, peak flame temperature) compared to the fuel lean or fuel rich fuel / oxidant ratio. As a result, the diffuse flame can be substantially more stable than the premixed flame, which ensures that the diffusion of fuel and oxidizer maintains a stoichiometric ratio (and higher temperature) along the flame surface. Due to helping. The higher the flame temperature, the more exhaust emissions such as NOx emissions can occur, but in the disclosed embodiments, one or more diluents are used to premix any fuel and oxidant. Temperature and emissions can still be controlled while avoiding. For example, the disclosed embodiments may introduce one or more diluents separately from the fuel and oxidizer (eg, after the combustion point and / or downstream from the diffusion flame), thereby allowing. It can help lower the temperature and reduce the emissions (eg, NOx emissions) produced by the diffuse flame.
0016In the disclosed embodiments, the exhaust gas provided by the exhaust gas recirculation (EGR) functions as at least one of the diluents. Exhaust gas (as one of the diluents) is essentially decoupled from the oxidant and fuel flow, which allows independent control of the fuel, oxidant, and diluent (eg, exhaust) flow. To. In certain embodiments, the exhaust gas is injected into the turbine combustor after the combustion point and / or downstream from the flame (eg, premixed flame and / or diffuse flame), thereby lowering the temperature. It can help reduce exhaust emissions, such as NOx emissions. However, other diluents (eg, steam, nitrogen, or other inert gases) can also be used alone or in combination with exhaust gases for temperature and / or emission control. Judging from the difference between the premixed flame and the diffuse flame, the amount of EGR can vary significantly between the gas turbine system operating on the premixed fuel nozzle vs. the diffuse fuel nozzle. The premixed flame may be constrained to the premixed mixture upstream from the premixed flame (including, for example, a mixture of fuel and oxidizer and diluent), so the premixed flame is at a constant level of EGR. It is not possible to maintain flame stability above. In other words, in a premixed flame configuration of a gas turbine system, an increased amount of exhaust gas premixed with fuel and oxidants (eg, EGR) can further reduce the temperature and flame stability of the premixed flame. Yes, and therefore an excess of EGR can destabilize the premixed flame. However, in a diffuse flame configuration of a gas turbine system, it is here that an increased amount of exhaust gas (eg, EGR) can be used with a diffuse flame well above any of the limits associated with the premixed flame configuration. Conceivable. For example, in a substantially quantitative EGR gas turbine system, the amount of exhaust gas (EGR) that can be used in a diffuse flame configuration is the exhaust gas (eg, EGR) that can be used in a premixed flame configuration. More than less than the amount of It can be at least about 10, 20, 30, 40, 50, 60, 70, 80, 90, or 100 percent. According to another embodiment, in a substantially quantitative EGR gas turbine system, the amount of exhaust gas (EGR) that can be used in a diffuse flame configuration is relative to the total flow rate through the combustor and turbine sections. Exhaust gas (eg, EGR) can be greater than about 35, 40, 45, 50, 55, 60, 65, 70, or 75 volume percent. As a result, by using a diffuse flame (eg, a diffuse flame nozzle) with a virtually stoichiometric EGR gas turbine system, CO<sub>2</sub>Significant improvements in production can be achieved.
0017Diffusion fuel nozzles are EGR and CO<sub>2</sub>Although it may be particularly helpful in increasing the amount of production, the disclosed embodiments use different controls to fuel / even if the system is operating in a premixed flame, a diffuse flame, or a combination thereof. Helps control oxidant ratio, flame stability, exhaust emissions, and power output. For example, a disclosed embodiment may include a combustor with one or more diffusion fuel nozzles and a premixed fuel nozzle, which are independently controlled by different fluid supply circuits and have a premixed flame configuration. And the benefits of both diffuse flame configurations can be provided.
0018FIG. 1 is a schematic representation of one embodiment of system 10 having a hydrocarbon generation system 12 associated with a turbine-based service system 14. As discussed in more detail below, various embodiments of the turbine-based service system 14 provide various services such as power, mechanical power, and fluid (eg, exhaust gas) to the hydrocarbon production system 12. , Is configured to facilitate the production or removal of oil and / or gas. In the illustrated embodiment, the hydrocarbon production system 12 includes an oil / gas extraction system 16 and a crude oil recovery (EOR) system 18, which are underground reservoirs 20 (eg, oil, gas, or hydrocarbon reservoirs). Combined with. The oil / gas extraction system 16 includes various offshore equipment (such as a Christmas tree or a generation tree 24) coupled to an oil / gas well 26. Further, the well 26 can include one or more pipes 28 extending through the drilling bore 30 in the underground 32 to the underground reservoir 20. The tree 24 includes one or more valves, chokes, separation sleeves, blowout preventers, and various flow control devices that regulate the pressure to and from the underground reservoir 20 to control the flow. The tree 24 is commonly used to control the flow of production fluid (eg, oil or gas) out of the underground reservoir 20, while the EOR system 18 draws one or more fluids into the underground reservoir 20. Oil or gas production can be increased by injecting into.
0019Thus, the EOR system 18 can include a fluid infusion system 34 having one or more tubes 36 extending into the underground reservoir 20 through a bore 38 in the ground 32. For example, EOR system 18 can send one or more fluids 40 (gas, vapor, water, chemicals, or any combination thereof) to fluid injection system 34. For example, as discussed in more detail below, the EOR system 18 is coupled to a turbine-based service system 14, so that the system 14 is virtually or completely oxygen-free. ) Is sent to the EOR system 18 so that it can be used as the injection fluid 40. The fluid infusion system 34 sends the fluid 40 (eg, exhaust gas 42) through one or more pipes 36 to the underground reservoir 20, as indicated by the arrow 44. The injection fluid 40 flows into the underground reservoir 20 through the pipe 36, which is offset 46 away from the pipe 28 of the oil / gas well 26. Therefore, the infusion fluid 40 moves the oil / gas 48 located in the underground reservoir 20 and transfers the oil / gas 48 to one or more tubes 28 of the hydrocarbon production system 12, as indicated by the arrow 50. Send upward through. As discussed in more detail below, the infusion fluid 40 produces exhaust gas 42 from a turbine-based service system 14, which is capable of generating exhaust gas 42 within the facility as needed by the hydrocarbon production system 12. Can include. In other words, the turbine-based system 14 has one or more services (eg, power, mechanical power, steam, water (eg, desalinated water)) and the exhaust gas used by the hydrocarbon production system 12 (eg, substantially). (Without oxygen) can be generated simultaneously, thereby reducing or eliminating the dependence of such services on external sources.
0020In the illustrated embodiment, the turbine-based service system 14 includes a quantitative exhaust gas recirculation (SEGR) gas turbine system 52 and an exhaust gas (EG) treatment system 54. The gas turbine system 52 comprises a stoichiometric combustion operating mode (eg, stoichiometric control mode) and a non-stoichiometric combustion operating mode (eg, non-stoichiometric control), such as fuel lean control mode or fuel rich control mode. It can be configured to operate in mode). In the quantitative control mode, the combustion generally occurs in a substantially stoichiometric ratio of the fuel and the oxidant, which results in a substantially stoichiometric combustion. In particular, stoichiometric combustion generally consumes substantially all of the fuel and oxidizer in the combustion reaction so that the combustion products are substantially or completely free of unburned fuel and oxidizer. Accompanied by. One measure of stoichiometric combustion is the equivalent ratio, or phi (Φ), which is the ratio of the actual fuel / oxidizer ratio to the stoichiometric fuel / oxidizer ratio. Equivalent ratios greater than 1.0 result in fuel-rich combustion of fuels and oxidants, while equivalent ratios less than 1.0 result in fuel lean combustion of fuels and oxidants. In contrast, an equivalent ratio of 1.0 results in combustion that is neither fuel rich nor fuel lean, thus consuming substantially all of the fuel and oxidizer in the combustion reaction. In the context of the disclosed embodiments, the term "stoichiometry" or "stoichiometry" can refer to an equivalent ratio of about 0.95 to about 1.05. However, the disclosed embodiments also have equivalent ratios of 1.0 ± 0.01, 0.02, 0.03, 0.04, 0. 05 or more can be included. Again, the stoichiometric combustion of fuel and oxidizer in the turbine-based service system 14 produces combustion products or exhaust gases (eg, 42) that are virtually free of residual unburned fuel or oxidizer. Can bring. For example, the exhaust gas 42 contains less than 1, 2, 3, 4, or 5 volume percent oxidants (eg, oxygen), unburned fuels or hydrocarbons (eg, HC), nitrogen oxides (eg, NOx), It can have carbon monoxide (CO), sulfur oxides (eg SOx), hydrogen, and other incomplete combustion products. According to another embodiment, the exhaust gas 42 is about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, Or less than 5000 ppmv (1 / 1,000,000 volume) of oxidizer (eg oxygen), unburned fuel or hydrocarbon (eg HC), nitrogen oxides (eg NOx), carbon monoxide (CO), sulfur oxidation Things (eg SO<sub>X</sub>), Hydrogen, and other incomplete combustion products. However, the disclosed embodiments also produce other ranges of residual fuel, oxidants, and other emission levels in the exhaust gas 42. As used herein, the terms "emission", "emission level", and "emission target" are specific combustion products (eg, NOx, CO, SOx, O).<sub>2</sub>, N<sub>2</sub>, H<sub>2</sub>, HCs, etc.), which can refer to recirculated gas streams, released gas streams (eg, exhausted into the atmosphere), and various target systems (eg, hydrocarbons). It can be present in the gas stream used in the production system 12).
0021The SEGR gas turbine system 52 and the EG treatment system 54 can include various components in different embodiments, but the illustrated EG treatment system 54 includes a heat recovery steam generator (HRSG) 56 and exhaust gas recirculation ( EGR) systems 58 are included, which receive and process the exhaust gas 60 generated from the SEGR gas turbine system 52. The HRSG56 can include one or more heat exchangers, condensers, and various heat recovery facilities, which as a whole transfer heat from the exhaust gas 60 to the water stream to generate steam 62. Works like Steam 62 can be used in one or more steam turbines, the EOR system 18, or any other part of the hydrocarbon production system 12. For example, the HRSG56 can produce low-pressure, medium-pressure, and / or high-pressure steam 62, which are selectively applied to different applications of low-pressure, medium-pressure, and high-pressure steam turbine stages or EOR systems 18. be able to. In addition to steam 62, treated water 64, such as desalinated water, can be produced by HRSG56, EGR system 58, and / or another part of EG treatment system 54 or SEGR gas turbine system 52. Treated water 64 (eg, desalinated water) can be particularly useful in water-scarce areas such as inland or desert areas. The treated water 64 can be produced at least partially by the large amount of air that causes the combustion of fuel within the SEGR gas turbine system 52. In-house production of steam 62 and 64 is beneficial for many applications (including hydrocarbon production system 12), while in-house production of exhaust gases 42, 60 is from the SEGR gas turbine system 52. Due to the low oxygen content, high pressure and heat produced, it can be particularly beneficial to the EOR system 18. Thus, another part of the HRSG56, EGR system 58, and / or EG processing system 54 can output or recirculate the exhaust gas 66 to the SEGR gas turbine system 52 while using the exhaust gas 42 with the hydrocarbon generation system 12. To do Can be sent to EOR system 18 for. Similarly, the exhaust gas 42 can be extracted directly from the SEGR gas turbine system 52 (ie, without passing through the EG treatment system 54) for use in the EOR system 18 of the hydrocarbon production system 12.
0022Exhaust gas recirculation is processed by the EGR system 58 of the EG processing system 54. For example, the EGR system 58 may include one or more conduits, valves, blowers, exhaust gas treatment systems (eg, filters, particulate matter removal units, gas separation units, gas purification units, heat exchangers, heat recovery units, dehumidification). Inputs (eg, exhaust gas 60) from the SEGR gas turbine system 52 output (eg, exhaust gas 60) along the exhaust gas circulation path, including units, catalyst units, chemical injection units, or combinations thereof). , Recirculate the exhaust gas to the inhaled exhaust gas 66). In the illustrated embodiment, the SEGR gas turbine system 52 causes the exhaust gas 66 to be sucked into a compressor section having one or more compressors, thereby compressing the exhaust gas 66 and oxidizing agents 68 and 1 or 2. Used in the compressor section with the above fuel 70 inhalation. The oxidant 68 can include ambient air, pure oxygen, oxygen-enriched air, oxygen-deficient air, an oxygen-nitrogen mixture, or any suitable oxidant that facilitates combustion of the fuel 70. The fuel 70 can include one or more gas fuels, liquid fuels, or any combination thereof. For example, fuel 70 can include natural gas, liquefied natural gas (LNG), syngas, methane, ethane, propane, butane, naphtha, kerosine, diesel fuel, ethanol, methanol, biofuel, or any combination thereof. ..
0023The SEGR gas turbine system 52 mixes and burns exhaust gas 66, oxidant 68, and fuel 70 in the combustor section, thereby driving one or more turbine stages in the turbine section with hot combustion gas or exhaust. Generates gas 60. In certain embodiments, each combustor in the combustor section comprises one or more premixed fuel nozzles, one or more diffusion fuel nozzles, or any combination thereof. For example, each premixed fuel nozzle mixes oxidizer 68 and fuel 70 inside the fuel nozzle and / or partially upstream of the fuel nozzle, thereby causing premixed combustion (eg, premixed flame). Therefore, the oxidizer-fuel mixture can be configured to be injected through the fuel nozzle into the combustion zone. According to another embodiment, each diffusion fuel nozzle separates the flow of oxidant 68 and fuel 70 within the fuel nozzle, thereby fueling oxidizer 68 and fuel 70 for diffusion combustion (eg, diffusion flame). It can be configured to inject separately from the nozzle into the combustion zone. Specifically, the diffusion combustion provided by the diffusion fuel nozzle delays the mixing of oxidant 68 and fuel 70 to the point of initial combustion, the flame region. In an embodiment utilizing a diffusion fuel nozzle, the diffusion flame is generally at a stoichiometric point between separate streams of oxidant 68 and fuel 70 (ie, when oxidant 68 and fuel 70 are mixed). Since it is formed, flame stability can be improved. In certain embodiments, one or more diluents (eg, exhaust gas 60, steam, nitrogen, or another inert gas) are oxidizer 68, fuel in either the diffusion fuel nozzle or the premixed fuel nozzle. Can be premixed with 70 or both. In addition, one or more diluents (eg, exhaust gas 60, vapor, nitrogen, or another inert gas) are placed in the combustor at the combustion point in each combustor or downstream thereof. Can be infused. The use of these diluents aids in the conditioning of flames (eg, premixed flames or diffuse flames), thereby nitric oxide (N).<sub>2</sub>) Can help reduce NOx emissions. Regardless of the type of flame, combustion produces hot combustion gas or exhaust gas 60 to drive one or more turbine stages. When each turbine stage is driven by exhaust gas 60, the SEGR gas turbine system 52 produces mechanical output 72 and / or electrical output 74 (eg, via a generator). System 52 can also output exhaust gas 60 and further water 64. In this case as well, the water 64 can be treated water such as desalted water, which can be useful for various uses inside or outside the equipment.
0024Exhaust gas extraction is also provided by the SEGR gas turbine system 52 with one or more extraction points 76. For example, in the illustrated embodiment, the exhaust gas (EG) extraction system 80 receives the exhaust gas 42 from the extraction point 76, processes the exhaust gas 42, and then supplies or distributes the exhaust gas 42 to various target systems. And an exhaust gas (EG) supply system 78 with an exhaust gas (EG) treatment system 82. Target systems can include EOR system 18, and / or other systems such as pipeline 86, storage tank 88, or carbon sequestration system 90. The EG extraction system 80 can include one or more conduits, valves, controls, and flow separators that isolate the exhaust gas 42 from the oxidizer 68, fuel 70, and other contaminants. At the same time, it makes it possible to control the temperature, pressure, and flow rate of the extracted exhaust gas 42. The EG processing system 82 includes one or more heat exchangers (eg, a heat recovery unit such as a heat recovery steam generator, a condenser, a cooler, or a heater), a catalytic system (eg, an oxidation catalyst system), and particles. Material and / or water removal systems (eg gas dehydration units, inertial force sorters, coagulation filters, water impermeable filters, and other filters), chemical injection systems, solvent-based treatment systems (eg absorbers, flashes) Tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and / or solvent-based treatment systems, exhaust gas compressors, any combination thereof. These subsystems of the EG treatment system 82 allow for temperature, pressure, flow rate, water content (eg, water removal), particulate matter content (eg, particulate matter removal), and gas composition (eg, CO).<sub>2</sub>, N<sub>2</sub>, Other ratios) can be controlled.
0025The extracted exhaust gas 42 is processed by one or more subsystems of the EG processing system 82, depending on the target system. For example, the EG treatment system 82 can orient some or all of the exhaust gas 42 through a carbon capture system, a gas separation system, a gas purification system, and / or a solvent-based treatment system and is used in various target systems. For carbon-containing gas (eg carbon dioxide) 92 and / or nitrogen (N)<sub>2</sub>) 94 is controlled to separate and purify. For example, an embodiment of the EG treatment system 82 performs gas separation and purification to produce a plurality of different streams 95 of exhaust gas 42, such as the first stream 96, the second stream 97, and the third stream 98. Can be generated. The first stream 96 is rich in carbon dioxide and / or lean in nitrogen (eg, CO).<sub>2</sub>Rich N<sub>2</sub>It can have a first composition that is lean stream). The second stream 97 is an intermediate concentration level of carbon dioxide and / or nitrogen (eg, intermediate concentration CO).<sub>2</sub> N<sub>2</sub>It can have a second composition that is a stream). The third stream 98 is carbon dioxide lean and / or nitrogen rich (eg, CO).<sub>2</sub>Lean N<sub>2</sub>It can have a third composition that is (rich stream). Each stream 95 (eg, 96, 97, and 98) may include a gas dehydration unit, filter, gas compressor, or any combination thereof to facilitate delivery of the stream 95 to the target system. it can. In certain embodiments, CO<sub>2</sub>Rich N<sub>2</sub>Lean Stream 96 is about 70, 75, 80, 85, 90, 95, 96, 97, 98, or more than 99 volume percent CO<sub>2</sub>Purity or concentration level and N less than about 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 volume percent<sub>2</sub>It can have a purity or concentration level. In contrast, CO<sub>2</sub>Lean N<sub>2</sub>Rich Stream 98 is less than about 1, 2, 3, 4, 5, 10, 15, 20, 25, or 30 volume percent CO<sub>2</sub>Purity or concentration level and N greater than about 70, 75, 80, 85, 90, 95, 96, 97, 98, or 99 volume percent<sub>2</sub>It can have a purity or concentration level. Intermediate concentration CO<sub>2</sub> N<sub>2</sub>Stream 97 is about 30-70, 35-65, 40-60, or 45-55 volume percent CO<sub>2</sub>Purity or concentration level and / or N<sub>2</sub>It can have a purity or concentration level. The above scope is merely a non-limiting example, CO<sub>2</sub>Rich N<sub>2</sub>Lean Stream 96 and CO<sub>2</sub>Lean N<sub>2</sub>Richstream 98 can be particularly suitable for use with the EOR system 18 and other systems 84. However, these rich, lean, or intermediate concentrations of CO<sub>2</sub>Any of the streams 95 can be used alone or in various combinations with the EOR system 18 and other systems 84. For example, EOR system 18 and other systems 84 (eg, pipeline 86, storage tank 88, and carbon sequestration system 90) each have one or more COs.<sub>2</sub>Rich N<sub>2</sub>Lean stream 96, 1 or 2 or more CO<sub>2</sub>Lean N<sub>2</sub>Rich stream 98, intermediate concentration CO of 1 or 2 or more<sub>2</sub> N<sub>2</sub>Stream 97 and one or more 42 streams of untreated exhaust gas (ie, bypassing the EG treatment system 82) can be received.
0026The EG extraction system 80 extracts exhaust gas 42 at one or more extraction points 76 along the compressor section, combustor section, and / or turbine section, and exhaust gas 42 at a suitable temperature and pressure. Make it available in EOR system 18 and other systems 84. The EG extraction system 80 and / or the EG treatment system 82 can also circulate a fluid flow (eg, exhaust gas 42) to and from the EG treatment system 54. For example, a portion of the exhaust gas 42 passing through the EG processing system 54 can be extracted by the EG extraction system 80 for use in the EOR system 18 and other systems 84. In certain embodiments, the EG supply system 78 and the EG processing system 54 can be independent or integrated with each other, and thus can use independent subsystems or common subsystems. For example, the EG processing system 82 can be used by both the EG supply system 78 and the EG processing system 54. Exhaust gas 42 extracted from the EG treatment system 54 may be plural, such as one or more gas treatment stages in the EG treatment system 54 and one or more additional gas treatment stages in the subsequent EG treatment system 82. Can receive the gas treatment stage of.
0027At each extraction point 76, the extracted exhaust gas 42 is substantially due to quantitative combustion and / or gas treatment in the EG treatment system 54, substantially oxidant 68 and fuel 70 (eg, unburned fuel). Or hydrocarbons) may not be present. In addition, depending on the target system, the extracted exhaust gas 42 undergoes further treatment in the EG treatment system 82 of the EG supply system 78, which produces some residual oxidant 68, fuel 70, or other unwanted combustion. Things can be further reduced. For example, before or after treatment of the EG treatment system 82, the extracted exhaust gas 42 contains less than 1, 2, 3, 4, or 5 volume percent of oxidants (eg, oxygen), unburned fuels or hydrocarbons. It can have (eg, HC), nitrogen oxides (eg, NOx), carbon monoxide (CO), sulfur oxides (eg, SOx), hydrogen, and other incomplete combustion products. According to another embodiment, before or after the treatment of the EG treatment system 82, the extracted exhaust gas 42 is about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 200, Less than 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 ppmv (1 / 1,000,000 volume) oxidizer (eg oxygen), unburned fuel or hydrocarbon (eg HC), nitrogen oxides It can have (eg, NOx), carbon monoxide (CO), sulfur oxides (eg, SOx), hydrogen, and other incomplete combustion products. Therefore, the exhaust gas 42 is particularly suitable for use with the EOR system 18.
0028The EGR operation of the turbine system 52 specifically allows exhaust gas extraction at multiple positions 76. For example, the compressor section of system 52 can be used to compress exhaust gas 66 without any oxidant 68 (ie, only compression of exhaust gas 66), resulting in oxidant 68 and fuel 70. Exhaust gas 42, which is substantially oxygen-free, can be extracted from the compressor section and / or the combustor section prior to the inflow of. Extraction point 76 is located at the interstage port between adjacent compressor stages, at the port along the compressor exhaust casing, at the port along each combustor in the combustor section, or a combination thereof. be able to. In certain embodiments, the exhaust gas 66 can be prevented from mixing with the oxidant 68 and the fuel 70 until it reaches the head end portion and / or the fuel nozzle of each combustor in the combustor section. In addition, one or more flow separators (eg, walls, dividers, baffles, or the like) can be used to isolate oxidant 68 and fuel 70 from extraction point 76. With these flow separators, the extraction point 76 can be placed directly along the wall of each combustor in the combustor section.
0029When the exhaust gas 66, the oxidant 68, and the fuel 70 flow into the combustion part (eg, combustion chamber) of each combustor through the end of the head (eg, through the fuel nozzle), the SEGR gas turbine system 52 , Exhaust gas 66, oxidant 68, and fuel 70 are controlled to result in a substantially quantitative combustion. For example, system 52 can maintain an equivalent ratio of about 0.95 to about 1.05. As a result, the combustion products of the mixture of exhaust gas 66, oxidizer 68, and fuel 70 in each combustor are substantially free of oxygen and unburned fuel. Therefore, the combustion product (or exhaust gas) can be extracted from the turbine section of the SEGR gas turbine system 52 for use as the exhaust gas 42 sent to the EOR system 18. Along the turbine section, extraction point 76 can be located at any turbine stage, such as an interstage port between adjacent turbine stages. Thus, using any of the extraction points 76 described above, the turbine-based service system 14 produces and extracts the exhaust gas 42 and sends it to the hydrocarbon production system 12 (eg, the EOR system 18) for an underground reservoir. It can be used to generate oil / gas 48 from 20.
0030FIG. 2 is a schematic representation of one embodiment of system 10 of FIG. 1 showing a control system 100 coupled to a turbine-based service system 14 and a hydrocarbon production system 12. In the illustrated embodiment, the turbine-based service system 14 includes a combined cycle system 102, wherein the combined cycle system 102 is from a SEGR gas turbine system 52 as a topping cycle, a steam turbine 104 as a bottoming cycle, and exhaust gas 60. Includes the HRSG56, which recovers heat and generates steam 62 to drive the steam turbine 104. Similarly, in this case, the SEGR gas turbine system 52 receives the exhaust gas 66, the oxidizer 68, and the fuel 70, mixes them, and performs quantitative combustion (for example, premixing and / or diffusion flame). Produces exhaust gas 60, mechanical output 72, electrical output 74, and / or water 64. For example, the SEGR gas turbine system 52 is a load of one or more such as a generator, an oxidant compressor (eg, a main air compressor), a gearbox, a pump, equipment for a hydrocarbon generation system 12, or a combination thereof. Alternatively, the mechanical device 106 can be driven. In some embodiments, the mechanical device 106 may include other drive devices such as a generator or steam turbine (eg, steam turbine 104) arranged in tandem with the SEGR gas turbine system 52. Thus, the output of mechanical device 106 driven by the SEGR gas turbine system 52 (and any additional drive) can include mechanical output 72 and electrical output 74. Mechanical output 72 and / or electrical output 74 can be used in the facility to power the hydrocarbon production system 12, and electrical output 74 can be distributed to the grid or a combination thereof. The output of the mechanical device 106 can also include a compressed fluid such as a compressible oxidant 68 (eg, air or oxygen) for suction into the combustion section of the SEGR gas turbine system 52. These outputs (eg exhaust gas 60)
0031The SEGR gas turbine system 52 produces exhaust gases 42, 60, which may be substantially oxygen-free, and sends the exhaust gases 42, 60 to the EG processing system 54 and / or the EG supply system 78. The EG supply system 78 can process the exhaust gas 42 (eg, stream 95) and feed it to the hydrocarbon production system 12 and / or another system 84. As discussed above, the EG processing system 54 can include the HRSG56 and the EGR system 58. The HRSG56 can include one or more heat exchangers, condensers, and various heat recovery facilities, which are used to recover heat from the exhaust gas 60 and transfer it to the water 108 to bring the steam turbine 104 to the steam turbine 104. It can generate steam 62 to drive. Similar to the SEGR gas turbine system 52, the steam turbine 104 can drive one or more loads or mechanical devices 106, which can generate mechanical output 72 and electrical output 74. In the illustrated embodiment, the SEGR gas turbine system 52 and the steam turbine 104 are arranged in a vertical row to drive the same mechanical device 106. However, in other embodiments, the SEGR gas turbine system 52 and steam turbine 104 can drive different mechanical devices 106 separately and independently generate mechanical output 72 and / or electrical output 74. When the steam turbine 104 is driven by steam 62 from HRSG56, the temperature and pressure of steam 62 gradually decrease. Therefore, the steam turbine 104 recirculates the used steam 62 and / or water 108 back to the HRSG 56 to generate additional steam through heat recovery from the exhaust gas 60. In addition to steam generation, another part of the HRSG56, EGR system 58, and / or EG treatment system 54 is to water 64, and exhaust gas 42 for use with the hydrocarbon production system 12, and to the SEGR gas turbine system 52. Exhaust gas 66 to be used as an input can be generated. For example, water 64 is like desalinated water for other uses. It can be treated water 64. Demineralized water can be particularly useful in areas where water availability is low. With respect to the exhaust gas 60, embodiments of the EG treatment system 54 can be configured to recirculate the exhaust gas 60 through the EGR system 58 regardless of whether the exhaust gas 60 is passed through the HRSG56.
0032In the illustrated embodiment, the SEGR gas turbine system 52 has an exhaust gas recirculation path 110 extending from the exhaust outlet of the system 52 to the exhaust inlet. The exhaust gas 60 passes along the path 110 through an EG processing system 54, including the HRSG 56 and the EGR system 58, in the illustrated embodiment. The EGR system 58 is arranged in series and / or in parallel along the path 110 with one or more conduits, valves, blowers, gas treatment systems (eg, filters, particulate matter removal units, gas separation units, gas purification units). , Heat exchangers, heat recovery units such as heat recovery steam generators, dehumidifying units, catalyst units, chemical injection units, or combinations thereof). In other words, the EGR system 58 includes any flow control component, pressure control component, temperature control component, along the exhaust gas recirculation path 110 between the exhaust gas outlet and the exhaust gas inlet of the system 52. Humidity control components and gas composition control components can be included. Thus, in embodiments with the HRSG56 along the path 110, the HRSG56 can be considered as one component of the EGR system 58. However, in certain embodiments, the HRSG56 can be placed along the exhaust gas path independently of the exhaust gas recirculation path 110. Regardless of whether the HRSG56 follows a separate route from the EGR system 58 or a common route, the HRSG56 and the EGR system 58 inhale the exhaust gas 60 and recirculate the exhaust gas 60. Or the exhaust gas 42 for use with the EG supply system 78 (eg for the hydrocarbon production system 12 and / or another system 84), or an exhaust gas of another output. Similarly, in this case, the SEGR gas turbine system 52 sucks in and mixes exhaust gas 66, oxidizer 68, and fuel 70 (eg, premixed flame and / or diffused flame), and quantitatively burns them. For distribution to EG processing system 54, hydrocarbon production system 12, or other system 84
0033As mentioned above with reference to FIG. 1, the hydrocarbon generation system 12 can include various equipment to facilitate the recovery or production of oil / gas 48 from the underground reservoir 20 through the oil / gas well 26. For example, the hydrocarbon production system 12 can include an EOR system 18 with a fluid injection system 34. In the illustrated embodiment, the fluid injection system 34 includes an exhaust gas injection EOR system 112 and a steam injection EOR system 114. The fluid injection system 34 can receive fluids from various sources, but the illustrated embodiment can receive exhaust gas 42 and steam 62 from a turbine-based service system 14. The exhaust gas 42 and / or steam 62 produced by the turbine-based service system 14 can also be sent to the hydrocarbon production system 12 for use in other oil / gas systems 116.
0034The quantity, quality, and flow of exhaust gas 42 and / or steam 62 can be controlled by control system 100. The control system 100 can be completely dedicated to the turbine-based service system 14, or optionally control the hydrocarbon production system 12 and / or other systems 84. In the illustrated embodiment, the control system 100 includes a controller 118 having a processor 120, a memory 122, a steam turbine control unit 124, a SEGR gas turbine system control unit 126, and a mechanical control unit 128. Processor 120 may include a single processor to control the turbine-based service system 14, or two or more redundant processors such as triple redundant processors. The memory 122 may include volatile and / or non-volatile memory. For example, memory 122 can include one or more hard drives, flash memory, read-only memory, random access memory, or a combination thereof. Controls 124, 126, and 128 may include software and / or hardware controls. For example, controls 124, 126, and 128 may include various instructions or codes stored in memory 122 and executed by processor 120. The control unit 124 is configured to control the operation of the steam turbine 104, the SEGR gas turbine system control unit 126 is configured to control the system 52, and the mechanical control unit 128 is configured to control the mechanical device 106. To. Thus, controllers 118 (eg, controls 124, 126, and 128) coordinate the various subsystems of the turbine-based service system 14 to provide the hydrocarbon generation system 12 with a suitable stream of exhaust gas 42. Can be configured to.
0035In certain embodiments of control system 100, each element (eg, system, subsystem, and component) shown in the drawings and described herein is (eg, directly within such element). It contains one or more industrial control feature elements such as sensors and control devices (on the upstream side or downstream side), which together with the controller 118 are communicably coupled to each other via the industrial control network. For example, the control device associated with each element can include a dedicated device controller (including, for example, a processor, memory, and control instructions), one or more actuators, valves, switches, and industrial control equipment. , These allow control based on sensor feedback 130, control signals from controller 118, control signals from the user, or a combination thereof. Therefore, any of the control functions described herein can be performed using a controller 118, a dedicated device controller associated with each element, or a control command stored and / or executable by a combination thereof. it can.
0036To enable such control functions, the control system 100 is used to obtain sensor feedback 130 for use in the execution of various control units (eg, control units 124, 126, and 128). Includes one or more sensors arranged throughout. For example, the sensor feedback 130 may span the SEGR gas turbine system 52, mechanical equipment 106, EG processing system 54, steam turbine 104, hydrocarbon generation system 12, or turbine-based service system 14 or hydrocarbon generation system 12. It can be obtained from sensors arranged across the components. For example, the sensor feedback 130 includes temperature feedback, pressure feedback, flow rate feedback, flame temperature feedback, combustion dynamics feedback, inhaled oxidant composition feedback, inhaled fuel composition feedback, exhaust gas composition feedback, mechanical output 72 output level, electrical output. It can include 74 power levels, 42 and 60 emissions, 64 water or quality, or a combination thereof. For example, the sensor feedback 130 can include a composition of exhaust gases 42, 60 that allows stoichiometric combustion in the SEGR gas turbine system 52. For example, the sensor feedback 130 includes one or more inhaled oxidant sensors along the oxidant supply path of oxidant 68, one or more inhaled fuel sensors along the fuel supply path of fuel 70, and exhaust gas refueling. It can include feedback from one or more exhaust emission sensors located along the circulation path 110 and / or inside the SEGR gas turbine system 52. The intake oxidant sensor, intake fuel sensor, and exhaust emission sensor can include a temperature sensor, a pressure sensor, a flow rate sensor, and a composition sensor. Emission sensors include nitrogen oxides (eg NOx sensors), carbon oxides (eg CO sensors and CO).<sub>2</sub>Sensors), sulfur oxides (eg SOx sensors), hydrogen (eg H)<sub>2</sub>Sensor), oxygen (eg O<sub>2</sub>Sensors), unburned hydrocarbons (eg, HC sensors), or other incomplete combustion products, or sensors for combinations thereof.
0037Using this feedback 130, the control system 100 keeps the equivalent ratio within a suitable range, eg, about 0.95 to about 1.05, about 0.95 to about 1.0, about 1.0 to about 1.05, or substantially 1.0. So, the intake flow of exhaust gas 66, oxidizer 68, and / or fuel 70 to the SEGR gas turbine system 52 (especially among other operating parameters) can be adjusted (eg, increased, decreased, or maintained). .. For example, control system 100 analyzes feedback 130 and exhaust emissions (eg, nitrogen oxides, CO and CO).<sub>2</sub>Concentration levels of carbon oxides, sulfur oxides, hydrogen, oxygen, unburned hydrocarbons, and other incomplete combustion products, such as) and / or equivalent ratios are determined, and then one or more. The components can be controlled to adjust the exhaust emissions (eg, the concentration level of exhaust gas 42) and / or the equivalent ratio. Controlled components are, but are not limited to, valves along the supply path for oxidant 68, fuel 70, and exhaust gas 66; oxidant compressor, fuel pump, or any of the EG treatment system 54. Components; Any component of the SEGR gas turbine system 52; or any of the components illustrated and described with reference to the drawings, including combinations thereof. The controlled component adjusts (eg, increases) the flow, temperature, pressure, or percentage (eg, equivalent ratio) of the oxidizer 68, fuel 70, and exhaust gas 66 that burn within the SEGR gas turbine system 52. Can be reduced or maintained). The components to be controlled are also catalyst units (eg, oxidation catalyst units), sources for catalyst units (eg, oxidative fuels, heat, electricity, etc.), gas purification and / or separation units (eg, solvent bases). It can include one or more gas treatment systems, such as separators, absorbers, flush tanks, etc.), and filtration units. The gas treatment system can help reduce various exhaust emissions along the exhaust gas recirculation path 110, the ventilation path (eg, exhausted into the atmosphere), or the extraction path to the EG supply system 78.
0038In certain embodiments, control system 100 analyzes feedback 130 and analyzes about 10, 20, 30, 40, 50, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, 5000, or Controlling one or more components to maintain or reduce emission levels (eg, exhaust gas 42 concentration levels, 60, 95) within a target range, such as less than 10000 ppmv (1 / 1,000,000 volume). Can be done. These target ranges are the same for each of the exhaust emissions (eg, concentration levels of nitrogen oxides, carbon monoxide, sulfur oxides, hydrogen, oxygen, unburned hydrocarbons, and other incomplete combustion products). Or can be different. For example, depending on the equivalent ratio, the control system 100 reduces the exhaust emissions (eg, concentration level) of the oxidant (eg, oxygen) to about 10, 20, 30, 40, 50, 60, 70, 80, 90, 100. Within the target range of less than 250, 500, 750, or 1000 ppmv, carbon monoxide (CO) exhaust emissions (eg, concentration levels) are less than about 20, 50, 100, 200, 500, 1000, 2500, or 5000 ppmv. The exhaust emissions (eg, concentration levels) of nitrogen oxides (NOx) can be selectively controlled within the target range of about 50, 100, 200, 300, 400, or less than 500 ppmv. .. In certain embodiments that operate in substantially stoichiometric equivalent ratios, the control system 100 reduces the exhaust emissions (eg, concentration levels) of the oxidant (eg, oxygen) to about 10, 20, 30, 40, 50, Selectively within the target range of less than 60, 70, 80, 90, or 100 ppmv, and carbon monoxide (CO) exhaust emissions within the target range of approximately 500, 1000, 2000, 3000, 4000, or less than 5000 ppmv. Can be controlled. Fuel lean equivalent ratio (for example, about 0.95 ~ 1. In a particular embodiment operating at 0), the control system 100 reduces the exhaust emissions (eg concentration levels) of the oxidant (eg oxygen) to about 500, 600, 700, 800, 900, 1000, 1100, 1200, Targets of approximately 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 150, or 200 ppmv of carbon monoxide (CO) exhaust emissions within the target range of less than 1300, 1400, or 1500 ppmv. The exhaust emissions of nitrogen oxides (eg, NOx) can be selectively controlled within a range and within a target range of less than about 50, 100, 150, 200, 250, 300, 350, or 400 ppmv. The target scope described above is merely an example and does not limit the scope of the disclosed embodiments.
0039The control system 100 can also be coupled to the local interface 132 and the remote interface 134. For example, the local interface 132 may include a computer workstation located within the facility in a turbine-based service system 14 and / or a hydrocarbon production system 12. In contrast, the remote interface 134 can include computer workstations located outside the facilities of the turbine-based service system 14 and the hydrocarbon production system 12, such as through an internet connection. These interfaces 132 and 134 allow monitoring and control of the turbine-based service system 14, such as through sensor feedback 130, operating parameters and one or more other graphic displays.
0040Again, as described above, controller 118 includes various controls 124, 126, and 128 that allow control of the turbine-based service system 14. The steam turbine control unit 124 can receive the sensor feedback 130 and output a control command that enables the operation of the steam turbine 104. For example, the steam turbine control unit 124 shows various indications of HRSG56, mechanical device 106, temperature and pressure sensors along the path of steam 62, temperature and pressure sensors along the path of water 108, and mechanical and electrical outputs 72. Sensor feedback 130 can be received from the sensor of. Similarly, the SEGR gas turbine system control unit 126 receives sensor feedback 130 from one or more sensors arranged along the SEGR gas turbine system 52, mechanical device 106, EG processing system 54, or a combination thereof. Can be done. For example, the sensor feedback 130 is from a temperature sensor, pressure sensor, clearance sensor, vibration sensor, flame sensor, fuel composition sensor, exhaust gas composition sensor, or a combination thereof, which is arranged inside or outside the SEGR gas turbine system 52. Obtainable. Finally, the mechanical control unit 128 can receive sensor feedback 130 from various sensors related to the mechanical output 72 and the electrical output 74 as well as sensors located within the mechanical device 106. Each of these controls 124, 126, and 128 uses sensor feedback 130 to improve the operation of the turbine-based service system 14.
0041In the illustrated embodiment, the SEGR gas turbine system control unit 126 has the quantity and quality of exhaust gases 42, 60, 95 in the EG processing system 54, the EG supply system 78, the hydrocarbon generation system 12, and / or other systems 84. Can execute instructions that control. For example, the SEGR gas turbine system control unit 126 keeps the level of oxidizer (eg, oxygen) and / or unburned fuel in the exhaust gas 60 below a threshold suitable for use with the exhaust gas infusion EOR system 112. be able to. In certain embodiments, this threshold level can be less than 1, 2, 3, 4, or 5% oxidant (eg, oxygen) and / or unburned fuel in a volume of exhaust gas 42,60. Or, the threshold levels of oxidants (eg, oxygen) and / or unburned fuels (and other exhaust emissions) are about 10, 20, 30, 40, 50, 60, 70, in exhaust gases 42, 60, It can be less than 80, 90, 100, 200, 300, 400, 500, 1000, 2000, 3000, 4000, or 5000 ppmv (one millionth volume). According to another embodiment, in order to achieve these low levels of oxidants (eg, oxygen) and / or unburned fuel, the SEGR gas turbine system control unit 126 is about to burn in the SEGR gas turbine system 52. An equivalent ratio of 0.95 to about 1.05 can be maintained. The SEGR gas turbine system control unit 126 also applies the temperature, pressure, flow rate, and gas composition of exhaust gases 42, 60, and 95 to the exhaust gas injection EOR system 112, pipeline 86, storage tank 88, and carbon isolation system 90. The EG extraction system 80 and the EG processing system 82 can be controlled so as to maintain the range. As discussed above, the EG processing system 82 is CO<sub>2</sub>Rich N<sub>2</sub>Lean stream 96, intermediate concentration CO<sub>2</sub> N<sub>2</sub>Stream 97, and CO<sub>2</sub>Lean N<sub>2</sub>The exhaust gas 42 into one or more gas streams 95, such as the rich stream 98, can be controlled to be purified and / or separated. In addition to controlling the exhaust gases 42, 60, and 95, controls 124, 126, and 128 maintain the mechanical output 72 within a suitable output range, or the electrical output 74 within a suitable frequency and output range. One or more instructions can be executed to maintain.
0042FIG. 3 is a schematic representation of an embodiment of system 10 that further illustrates the details of the SEGR gas turbine system 52 for use with the hydrocarbon generation system 12 and / or other systems 84. In the illustrated embodiment, the SEGR gas turbine system 52 includes a gas turbine engine 150 coupled to an EG processing system 54. The illustrated gas turbine engine 150 includes a compressor section 152, a combustor section 154, and an expander section or turbine section 156. Compressor section 152 includes one or more exhaust gas compressors or compressor stages 158, such as 1 to 20 stages of rotary compressor blades arranged in series. Similarly, the combustor section 154 includes one or more combustors 160, such as one to twenty combustors 160 arranged circumferentially around the axis of rotation 162 of the SEGR gas turbine system 52. In addition, each combustor 160 may include one or more fuel nozzles 164 configured to inject exhaust gas 66, oxidizer 68, and / or fuel 70. For example, the head end portion 166 of each combustor 160 can accommodate 1, 2, 3, 4, 5, 6, or more fuel nozzles 164, which fuel nozzles 66 exhaust gas, oxidize. A stream or mixture of agent 68 and / or fuel 70 can be injected into the combustion portion 168 (eg, combustion chamber) of the combustor 160.
0043The fuel nozzle 164 is a premixed fuel nozzle 164 (eg, configured to premix oxidant 68 and fuel 70 to generate an oxidant / fuel premixed flame) and / or a diffusion fuel nozzle 164 (eg, oxidation). Any combination of oxidizer 68 and fuel 70 (configured to inject separate streams) for the production of agent / fuel diffusion flames can be included. An embodiment of the premixed fuel nozzle 164 can include a swirl vane, a mixing chamber, or other feature element for internally mixing the oxidant 68 and the fuel 70 within the nozzle 164. The premixed fuel nozzle 164 can also receive the oxidant 68 and the fuel 70, which are at least partially mixed. In certain embodiments, each diffusion fuel nozzle 164 isolates the flow of oxidizer 68 and fuel 70 to the injection point while at the same time one or more diluents (eg, exhaust gas 66, vapor, nitrogen, etc.) to the injection point. Alternatively, the flow of another inert gas) can also be isolated. In another embodiment, each diffusion fuel nozzle 164 isolates the flow of oxidant 68 and fuel 70 to the injection point, but one or more diluents (eg, exhaust gas 66, steam, etc.) prior to the injection point. Nitrogen, or another inert gas), can be partially mixed with the oxidant 68 and / or the fuel 70. In addition, one or more diluents (eg, exhaust gas 66, vapor, nitrogen, or another inert gas) are in the combustor (eg, hot combustion products) in or downstream of the combustion zone. Injected into (inside), which lowers the temperature of the hot combustion products, NOx (eg NO and NO)<sub>2</sub>) Can help reduce emissions. Regardless of the type of fuel nozzle 164, the SEGR gas turbine system 52 can be controlled to provide substantially stoichiometric combustion of oxidant 68 and fuel 70.
0044During operation, as shown, the compressor section 152 receives the exhaust gas 66 from the EG processing system 54, compresses it, and then outputs the compressed exhaust gas 170 to each of the combustors 160 in the combustor section 154. .. As fuel 70, oxidizer 68, and exhaust gas 170 burn in each combustor 160, additional exhaust gas or combustion product 172 (ie, combustion gas) is sent to turbine section 156. Like the compressor section 152, the turbine section 156 includes one or more turbines or turbine stages 174 that can have a series of rotary turbine blades. Here, these turbine blades are driven by the combustion product 172 generated in the combustor section 154, thereby driving the rotation of the shaft 176 coupled to the mechanical device 106. Again, the machinery 106 is any of the SEGR gas turbine systems 52, such as machinery 106, 178 coupled to turbine section 156 and / or machinery 106, 180 coupled to compressor section 152. It can include various devices coupled to the ends. In certain embodiments, mechanical devices 106, 178, 180 are in one or more generators, oxidant compressors for oxidant 68, fuel pumps for fuel 70, gearboxes, or SEGR gas turbine systems 52. Additional drives combined (eg, steam turbine 104, electric motors, etc.) can be included. As shown, the turbine section 156 outputs the exhaust gas 60 and recirculates from the exhaust gas outlet 182 of the turbine section 156 to the exhaust gas inlet 184 along the exhaust gas recirculation path 110 in the compressor section 152. to go into. Along the exhaust gas recirculation path 110, the exhaust gas 60 passes through the EG processing system 54 (eg, HRSG56 and / or EGR system 58) as discussed in detail above.
0045Again, each combustor 160 in combustor section 154 receives and mixes pressurized exhaust gas 170, oxidizer 68, and fuel 70 and burns quantitatively with additional exhaust gas or combustion. It produces product 172 to drive turbine section 156. In certain embodiments, the oxidant 68 is compressed by an oxidant compression system 186, such as a main air compression (MAC) system. The oxidant compression system 186 includes an oxidant compressor 188 coupled to the drive 190. For example, the drive unit 190 can include an electric motor, a combustion engine, or a combination thereof. In certain embodiments, the drive 190 can be a turbine engine, such as a gas turbine engine 150. Therefore, the oxidant compression system 186 can be an integral part of the mechanical device 106. In other words, the compressor 188 can be driven directly or indirectly by the mechanical output 72 supplied by the shaft 176 of the gas turbine engine 150. In such an embodiment, the compressor 188 depends on the output from the turbine engine 150, so the drive 190 may be excluded. However, in the illustrated embodiment, the oxidant compression system 186 is separated from the mechanical device 106. In any embodiment, the compression system 186 compresses the oxidant 68 and supplies it to the fuel nozzle 164 and the combustor 160. As discussed in more detail below, oxidizer 68 and fuel 70 allow separation and extraction of pressurized exhaust gas 170 without any oxidant 68 or fuel 70 that degrades the quality of pressurized exhaust gas 170. It can be supplied to the gas turbine engine 150 at a position specially selected to.
0046As shown in FIG. 3, the EG supply system 78 is located between the gas turbine engine 150 and the target system (eg, hydrocarbon production system 12 and other systems 84). Specifically, the EG supply system 78 (eg, the EG extraction system (EGES) 80) is at one or more extraction points 76 along the compressor section 152, the combustor section 154, and / or the turbine section 156. It can be combined with the gas turbine engine 150. For example, extraction points 76 are located between adjacent compressor stages, such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76 between compressor stages. can do. Each of these interstage extraction points 76 provides extraction exhaust gas 42 at different temperatures and pressures. Similarly, extraction points 76 are located between adjacent turbine stages, such as 2, 3, 4, 5, 6, 7, 8, 9, or 10 interstage extraction points 76 between turbine stages. be able to. Each of these interstage extraction points 76 provides extraction exhaust gas 42 at different temperatures and pressures. According to another embodiment, extraction points 76 can be located in multiple positions throughout the combustor section 154, which can provide different temperatures, pressures, flow rates, and gas compositions. Each of these extraction points 76 can include an EG extraction conduit, one or more valves, sensors, and controls, which selectively flow the extraction exhaust gas 42 to the EG supply system 78. It can be used to control.
0047The extracted exhaust gas 42 distributed by the EG supply system 78 has a controlled composition suitable for the target system (eg, hydrocarbon production system 12 and other systems 84). For example, at each of these extraction points 76, the exhaust gas 170 can be substantially isolated from the injection point (or flow) of the oxidant 68 and the fuel 70. In other words, the EG supply system 78 can be specially designed to extract the exhaust gas 170 from the gas turbine engine 150 without the addition of any oxidizer 68 or fuel 70. Further, in terms of stoichiometric combustion in each of the combustors 160, the extracted exhaust gas 42 can be substantially free of oxygen and fuel. The EG supply system 78 uses the exhaust gas 42 extracted for use in various processes such as secondary crude oil recovery, carbon sequestration, storage, or transportation to locations outside the facility to the hydrocarbon production system 12 and / or other. It can be sent directly or indirectly to system 84. However, in certain embodiments, the EG supply system 78 includes an EG treatment system (EGTS) 82 to further treat the exhaust gas 42 before use with the target system. For example, the EG processing system 82 is CO<sub>2</sub>Rich N<sub>2</sub>Lean stream 96, intermediate concentration CO<sub>2</sub> N<sub>2</sub>Stream 97, and CO<sub>2</sub>Lean N<sub>2</sub>Exhaust gas 42 to one or more streams 95, such as the rich stream 98, can be purified and / or separated. These treated exhaust stream 95 can be used individually or in some combination with the hydrocarbon production system 12 and other systems 84 (eg, pipeline 86, storage tank 88, and carbon sequestration system 90). ..
0048Similar to the exhaust gas treatment performed in the EG supply system 78, the EG treatment system 54 has a plurality of treatments, as indicated by element numbers 194, 196, 198, 200, 202, 204, 206, 208, and 210. Exhaust gas (EG) processing components 192 can be included. These EG processing components 192 (eg, 194 to 210) may be placed along the exhaust gas recirculation path 110 in one or more series, parallel, or any combination of series and parallel. it can. For example, the EG processing component 192 (eg, 194-210) can be in any order with one or more heat exchangers (eg, a heat recovery unit such as a heat recovery steam generator, a condenser, a cooler, or Heaters), catalytic systems (eg, oxidation catalyst systems), particulate matter and / or water removal systems (eg, inertial force sorters, coagulation filters, water impermeable filters, and other filters), chemical injection systems, It can include solvent-based treatment systems (eg, absorbers, flash tanks, etc.), carbon capture systems, gas separation systems, gas purification systems, and / or solvent-based treatment systems, or any combination thereof. In certain embodiments, the catalytic system is an oxidation catalyst, carbon monoxide reduction catalyst, nitrogen oxide reduction catalyst, aluminum oxide, zirconium oxide, silicone oxide, titanium oxide, platinum oxide, palladium oxide, cobalt. Oxides, mixed metal oxides, or combinations thereof can be included. The disclosed embodiments are intended to include any rearrangement of the above-mentioned components 192 in series and parallel arrays. As shown below, Table 1 shows some non-limiting examples of the arrangement of components 192 along the exhaust gas recirculation path 110.
0049table 1<img id="000003" he="125" wi="147" file="JP2016502016A_D0001.tif" img-format="tif" img-content="drawing" />
0050As shown above in Table 1, the catalyst unit is represented by CU, the oxidation catalyst unit is represented by OCU, the booth tabloa is represented by BB, the heat exchanger is represented by HX, and the heat recovery unit is represented by HRU. The heat recovery steam generator is represented by HRSG, the condenser is represented by COND, the steam turbine is represented by ST, the particulate matter removal unit is represented by PRU, the dehumidifying unit is represented by MRU, and the filter. Is represented by FIL, the agglomeration filter is represented by CFIL, the water impermeable filter is represented by WFIL, the inertial force sorter is represented by INER, and the diluent supply system (eg, steam, nitrogen, or other impermeable). Active gas) is represented by DIL. Table 1 shows the components 192 sequentially from the exhaust gas outlet 182 of the turbine section 156 to the exhaust gas inlet 184 of the compressor section 152, but is intended to include the reverse order of the components 192 shown. doing. In Table 1, any column (cell) containing two or more components is intended to include an integral unit with components, a parallel array of components, or a combination thereof. Further, in Table 1, HRU, HRSG, and COND are examples of HE, HRSG is an example of HRU, COND, WFIL, and CFIL are examples of WRU, INER, FIL, WFIL, And CFIL are examples of PRU, and WFIL and CFIL are examples of FIL. Again, Table 1 is not intended to exclude any sort of component 192 (not shown). In certain embodiments, the illustrated components 192 (eg, 194-210) can be partially or fully integrated within the HRSG56, EGR system 58, or a combination thereof. These EG treatment components 192 allow feedback control of temperature, pressure, flow rate and gas composition, while at the same time removing moisture and particulate matter from the exhaust gas 60. In addition, the treated exhaust gas 60 is 1 or 2 for use in the EG supply system 78.
0051As the treated recirculated exhaust 66 passes through compressor section 152, the SEGR gas turbine system 52 is one of the pressurized exhaust along one or more pipelines 212 (eg, bleed or bypass conduits). The part can be pulled out. Each line 212 sends the exhaust gas to one or more heat exchangers 214 (eg, cooling units), which can cool the exhaust gas for recirculation to the SEGR gas turbine system 52. For example, after passing through the heat exchanger 214, some of the cooled exhaust gas is a turbine section along the pipeline 212 for cooling and / or sealing of the turbine casing, turbine shroud, bearings, and other components. Can be sent to 156. In such an embodiment, the SEGR gas turbine system 52 does not send any oxidant 68 (or other potential contaminants) through the turbine section 156 for cooling and / or sealing purposes and is therefore cooled. Any leak of exhaust gas will not contaminate the hot combustion products (eg, working exhaust gas) that flow and drive the turbine stages of turbine section 156. According to another embodiment, after passing through the heat exchanger 214, some of the cooled exhaust gas goes to the upstream compressor stage of compressor section 152 along pipeline 216 (eg return conduit). It is fed, which can improve the compression efficiency by the compressor section 152. In such an embodiment, the heat exchanger 214 can be configured as an interstage cooling unit in the compressor section 152. In this way, the cooled exhaust gas helps improve the operating efficiency of the SEGR gas turbine system 52 while maintaining the purity of the exhaust gas (eg, substantially free of oxidants and fuels). Help out.
0052FIG. 4 is a flowchart of one embodiment of the operating process 220 of the system 10 shown in FIGS. 1 to 3. In certain embodiments, process 220 can be a computer-implemented process that accesses one or more instructions stored in memory 122 on processor 120 of controller 118 as shown in FIG. Execute the instruction with. For example, each step of process 220 can include instructions that can be executed by controller 118 of control system 100 as described with reference to FIG.
0053Process 220 can begin with the step of initiating the start mode of the SEGR gas turbine system 52 of FIGS. 1-3, as shown in block 222. For example, the start mode can include a gradual rise of the SEGR gas turbine system 52 to keep the thermal gradient, vibration, and clearance (eg, between rotating and fixed parts) within acceptable thresholds. For example, during start mode 222, process 220 can start supplying pressurized oxidant 68 to combustor 160 and fuel nozzle 164 of combustor section 154, as shown in block 224. .. In certain embodiments, the compressed oxidant can include compressed air, oxygen, oxygen-enriched air, oxygen-deficient air, an oxygen-nitrogen mixture, or a combination thereof. For example, the oxidant 68 can be compressed by the oxidant compression system 186 shown in FIG. Process 220 can also start supplying fuel to the combustor 160 and fuel nozzle 164 during start mode 222, as indicated by block 226. During start mode 222, process 220 can also start supplying exhaust gas (available) to combustor 160 and fuel nozzle 164, as shown in block 228. For example, the fuel nozzle 164 can generate one or more diffuse flames, premixed flames, or a combination of diffuse flames and premixed flames. During start mode 222, the exhaust gas 60 produced by the gas turbine engine 156 can be inadequate or unstable in quantity and / or quality. Therefore, during start-up mode, process 220 draws exhaust gas 66 from one or more storage units (eg, storage tank 88), pipeline 86, other SEGR gas turbine systems 52, or other exhaust gas sources. Can be supplied.
0054The process 220 can then burn the compressed oxidant, fuel, and exhaust gas mixture in the combustor 160 to produce the hot combustion gas 172, as shown in block 230. In particular, process 220 controls FIG. 2 to allow stoichiometric combustion of the air-fuel mixture (eg, stoichiometric diffusion combustion, premixed combustion, or both) in combustor 160 of combustor section 154. It can be controlled by system 100. However, maintaining stoichiometric combustion of the air-fuel mixture during start mode 222 can be particularly difficult (and thus low levels of oxidants and unburned fuels can be present in the hot combustion gas 172. There is sex). As a result, in start-up mode 222, the hot combustion gas 172 may have more residual oxidant 68 and fuel 70 than in steady-state mode, as discussed in more detail below. This allows process 220 to execute one or more control commands to reduce or eliminate residual oxidizer 68 and fuel 70 in the hot combustion gas 172 during start mode.
0055Process 220 then drives turbine section 156 with hot combustion gas 172, as shown in block 232. For example, the hot combustion gas 172 can drive one or more turbine stages 174 located within the turbine section 156. Downstream of turbine section 156, process 220 is capable of processing exhaust gas 60 from final turbine stage 174, as shown in block 234. For example, the exhaust gas treatment step 234 can include filtration, catalytic reaction of some residual oxidant 68 and / or fuel 70, chemical treatment, heat recovery with HRSG56, and the like. Process 220 can also recirculate at least a portion of the exhaust gas 60 to the compressor section 152 of the SEGR gas turbine system 52, as shown in block 236. For example, the exhaust gas recirculation step 236 can include the passage of the exhaust gas recirculation path 110 having the EG processing system 54, as shown in FIGS. 1 to 3.
0056The recirculated exhaust gas 66 can then be compressed in compressor section 152, as shown in block 238. For example, the SEGR gas turbine system 52 can sequentially compress the exhaust gas 66 recirculated in one or more compressor stages 158 of the compressor section 152. Subsequently, the pressurized exhaust gas 170 can be supplied to the combustor 160 and the fuel nozzle 164 as shown by the block 228. Steps 230, 232, 234, 236, and 238 can then be repeated until process 220 finally transitions to steady-state mode, as shown in block 240. At transition step 240, process 220 can continue to carry out steps 224-238, but can further initiate the extraction of exhaust gas 42 through the EG supply system 78, as shown in block 242. it can. For example, the exhaust gas 42 can be extracted from one or more extraction points 76 along the compressor section 152, the combustor section 154, and the turbine section 156, as shown in FIG. Process 220 can then supply the extracted exhaust gas 42 from the EG supply system 78 to the hydrocarbon production system 12, as shown in block 244. The hydrocarbon production system 12 can then inject exhaust gas 42 into the ground 32 for secondary crude oil recovery, as shown in block 246. For example, the extracted exhaust gas 42 can be used by the exhaust gas injection EOR system 112 of the EOR system 18 shown in FIGS.
0057FIG. 5 is a block schematic diagram of one embodiment of the EG processing system 54, as shown in FIGS. 1 to 3. In the illustrated embodiment, the EG treatment system 54 has a plurality of gas treatment systems 300, a valve 302, and a control system 100 coupled to sensors (S) distributed along an exhaust gas recirculation path 110. For example, each subsystem 300 and its components 192 may include one or more of valves 302 and sensors 304 located inside, upstream, and / or downstream of each subsystem 300 or component 192. Can include. Although not shown in FIG. 5, one or more valves 302 are located at or near each sensor 304, which allows greater flow control through the EG processing system 54. During operation, control system 100 can obtain sensor feedback 130 from sensor 304 and provide control signal 306 to valve 302, subsystem 300, and component 192 for control of EG processing system 54. The sensor feedback 130 can also include various sensor feedbacks from the SEGR gas turbine system 52, the EG supply system 78, and other components of the turbine-based service system 14.
0058Each of the gas treatment subsystems 300 can include one or more components that control temperature, pressure, gas composition, water content, particulate matter content, or any combination thereof. As shown in FIG. 5, the gas treatment subsystem 300 includes a catalyst and heat recovery (CHR) system 308, a dehumidification system (MRS) 310, and a particulate matter removal system (PRS) 312. The gas treatment subsystem 300 also includes one or more booth tabloars 314 that help enhance the flow and pressure of the exhaust gas 42 along the exhaust gas recirculation path 110. CHR308, booster 314, MRS310, and PRS310 are arranged in series in the illustrated embodiment, but other embodiments can rearrange these components in other series and / or parallel arrangements. ..
0059The CHR system 308 includes one or more catalyst units 316 and heat exchanger (HX) 318 arranged in series, in parallel, or integrally with each other. For example, the CHR system 308 can include a series of catalyst units 316 such as catalyst units 320, 322, 324, 326, and 328. The CHR system 308 can also include a series of heat exchangers 318 such as heat exchangers 330 and 332. The catalyst units 316 may be the same or different from each other. For example, one or more of the catalyst units 316 can include an oxidation catalyst unit (OCU) 334, which uses the oxidant fuel 336 to drive the oxidation reaction. Carbon monoxide (CO) and unburned hydrocarbon (HC) are converted to carbon dioxide (CO)<sub>2</sub>) And convert to water vapor. One or more of the catalyst units 316 are also nitrogen oxides (NO)<sub>X</sub>) To carbon dioxide (CO<sub>2</sub>), Nitrogen (N<sub>2</sub>), And a reduction reaction that converts to water can be driven. In the illustrated embodiment, the catalyst unit 320 is located upstream of the heat exchanger 330, the catalyst unit 322 is integrated within the heat exchanger 330, and the catalyst unit 324 is the heat exchanger 330 and the heat exchanger. The catalyst unit 326 is integrated with the heat exchanger 332, and the catalyst unit 328 is arranged downstream from the heat exchanger 332. However, various embodiments of the CHR system 308 may exclude or include any one or more of the catalyst units 316, or the catalyst units 316 are arranged in other sequences within the CHR system 308. can do.
0060The heat exchanger 318 is configured to transfer heat away from the exhaust gas 42 to one or more gases, liquids, or other fluids such as water. In the illustrated embodiment, each heat exchanger 318 includes a heat recovery unit (HRU) 338, the heat recovery unit (HRU) 338 from exhaust gas 42 for use in one or more other applications. It is configured to recover heat. For example, each of the illustrated heat recovery units 338 may include a heat recovery steam generator (HRSG) 340 so that the heat recovery steam generator (HRSG) 340 recovers heat from the exhaust gas 42 for the generation of steam 342. It is composed of. Steam 342 can be used in various processes within the EG processing system 54, EOR system 18, or elsewhere within the turbine-based service system 14. In the illustrated embodiment, each HRSG340 supplies steam 342 to one or more steam turbines (ST) 344, the steam turbine (ST) 344 driving one or more loads 346, and mechanical output 348. And / or an electrical output of 350 can be generated. For example, load 346 may include a generator that allows the generation of electrical output 350. The CHR system 308 shows the catalyst unit 316 and the heat exchanger 318 in a series arrangement, whereas another embodiment of the CHR system 308 arranges two or more of the catalyst unit 316 and the heat exchanger 318 in a parallel arrangement. Can be done. After the exhaust gas 42 has passed through the CHR system 308, the exhaust gas 42 can then flow one or more booth tabloa 314 before passing through the dehumidifying system 310 and the particular removal system 312.
0061The dehumidification system (MRS) 310 can include one or more dehumidification units (MRU) 352, such as the MRU 354 and 356. In the illustrated embodiment, the MRU 354 includes a heat exchanger 358, which transfers heat away from the exhaust gas 42 to another gas, liquid, or other fluid, thereby exhaust gas for dehumidification. 42 can be configured to cool. For example, the heat exchanger 358 can be included or configured as a condenser 360, which cools the exhaust gas 42 sufficiently and condenses the moisture in the exhaust gas 42 into water 362. It works to remove things. However, the MRU354 contains various cooling units (eg, 2, 3, 4, or more condensers, coolers, etc.) that condense the moisture from the exhaust gas 42, thereby producing water 362. Can be generated. The MRS310 can also include other water removal techniques such as filtration units. For example, the MRU356 can include one or more dehumidifying separators or filters 364, such as a water gas separator (WGS) 366, a water impermeable filter (WFIL) 368, and a coagulation filter (CFIL) 370. They can capture and remove moisture from the exhaust gas 42, producing an output of water 372. The MRS310 points to the MRU354 upstream of the MRU356, and other embodiments of the MRU310 allow the MRU356 to be positioned upstream of or in parallel with the MRU354. In addition, the MRS310 may include an additional dehumidifying filter 364, heat exchanger 358, or any other dehumidifying component. After the exhaust gas 42 has been treated by the MRS 310 to remove moisture, the exhaust gas 42 can then pass through the particulate matter removal system 312.
0062The Particulate Matter Removal System (PRS) 312 can include one or more Particulate Matter Removal System (PRU) 374 that can be arranged in series, in parallel, or in any combination thereof. For example, PRS312 can include PRU376 and PRU378 arranged in series. The PRU376 includes an inertial force sorter 380, a gravity sorter 382, or any other type of separation unit, or any combination thereof, thereby separating particulate matter 384 from the flow of exhaust gas 42. be able to. For example, the inertial force sorter 380 can include a centrifuge, which uses centrifugal force to drive particulate matter 384 out of the flow of exhaust gas 42. Similarly, the gravity sorter 382 can use gravity to drive the particulate matter 384 out of the flow of exhaust gas 42. The PRU 378 can include one or more particulate matter removal filters 386, such as the first stage filter 388 and the second stage filter 390. These stage filters 388 and 390 can gradually contain finer filter media such as thin film filters. However, the stage filters 388 and 390 can include a water impermeable filter (WFIL), an agglomeration filter (CFIL), a thin film filter, or a combination thereof. When the exhaust gas 42 passes through the first and second stage filters 388 and 390, the filter 386 captures or removes the particulate matter 392 from the exhaust gas 42. The illustrated PRS 312 has a PRU 376 on the upstream side of the PRU 378, but in other embodiments the PRU 378 can be positioned on the upstream side of the PRU 376 or in parallel with it. Once the exhaust gas 42 has been treated by the PRS 312, the exhaust gas 42 can then be recirculated back to the SEGR gas turbine system 52, as indicated by the arrow 110.
0063Along the exhaust gas recirculation path 110, the CHR system 308, MRS310, PRS312, and booth tabloa 314 are controlled by the control system 100, and the temperature of the exhaust gas 42, before flowing in and returning to the SEGR gas turbine system 52, The pressure, flow rate, moisture level, particulate matter level, and gas composition can be adjusted. For example, control system 100 receives sensor feedback 130 from various sensors 304 arranged along the exhaust gas recirculation path 110, thereby oxygen, carbon monoxide, hydrogen, nitrogen oxides (NO).<sub>X</sub>), Unburned hydrocarbons (HC), sulfur oxides (SO)<sub>X</sub>), Moisture, or any combination of these emissions (eg, concentration levels) can be fed back. In response to sensor feedback 130, control system 100 adjusts the pressure, temperature, or flow rate of exhaust gas 66, oxidizer 68, and fuel 70 delivered to SEGR gas turbine system 52 for combustion (eg, increase). , Decrease, or maintain). For example, the control system 100 responds to the sensor feedback 130 by the exhaust gas recirculation path 110, the inlet guide vane in the compressor section 152 of the gas turbine engine 150, the vent valve 394 leading to the vent system 396, or any of these. The valve 302 can be adjusted according to the combination, thereby adjusting the flow of the exhaust gas 42 to the compressor section 154 of the gas turbine engine 150.
0064In CHR system 308, control system 100 regulates the flow of oxidant fuel 336 to each of the catalyst units 316 in response to sensor feedback 130, thereby increasing or reducing the oxidative reaction within each catalyst unit 316. The gas composition of the exhaust gas 42, which recirculates and returns to the SEGR gas turbine system 52, can be changed. For example, control system 100 increases the flow of oxidant fuel 336 to increase the oxidative reaction within each UCU 334, thereby reducing the levels of carbon monoxide (CO) and unburned hydrocarbons (HC) and carbon dioxide. Carbon (CO)<sub>2</sub>) Level can be increased. Control system 100 also reduces the flow of oxidant fuel 336 to each of the UCU 334, thereby reducing carbon dioxide (CO).<sub>2</sub>) Can be lowered to raise the levels of carbon monoxide (CO) and unburned hydrocarbons (HC). The control system 100 also selectively increases or decreases the amount of exhaust gas, flowing each of the catalyst units 316, bypassing one or more of the catalyst units 316, or a combination thereof. be able to. The control system 100 can also selectively deliver the exhaust gas 42 by partially or completely bypassing one or more of the heat exchangers 318, such as the heat recovery unit 338. In this way, the control system 100 can raise or lower the temperature of the exhaust gas 42 and at the same time increase or decrease the amount of steam generated to drive the steam turbine 344.
0065In MRS310 and PRS312, the control system 100 can ensure sufficient removal of moisture and particulate matter in response to sensor feedback 130. For example, in response to a sensor feedback 130 indicating the water content, the control system 100 can control the MRU352 in the MRS310 to increase or decrease the dehumidification from the exhaust gas 42. In response to the sensor feedback 130 indicating the particulate matter content, the control system 100 can adjust the PRU 374 in the PRS 312, thereby increasing or decreasing the amount of particulate matter removed from the exhaust gas 42. Each of these control operations by the control system 100 can be based on feedback 130 from elsewhere within the EG processing system 54, SEGR gas turbine system 52, or turbine-based service system 14. In certain embodiments, the control system 100 determines the temperature, pressure, and / or flow rate of the exhaust gas 42 along the exhaust gas recirculation path 110 to the CHR system 308, MRS310, PRS312, or any of these components ( For example, internal, upstream, or downstream target ranges (eg, target temperature range, target pressure) of each subsystem and / or component, such as catalyst unit 316, heat exchanger 318, MRU352, PRU374, etc. It is configured to stay within the range (and target flow range). The control system 100 is within such a target range among various controlled changes in the SEGR gas turbine system 52, including changes in the flow of oxidizer 68, fuel 70, and diluent to the fuel nozzle 164 and combustor 160. Can be configured to maintain temperature, pressure, and / or flow rate.
0066FIG. 6 is a schematic representation of one embodiment of system 420 having an EG supply system 78 that extracts and processes the exhaust gas stream 95 and feeds it to various target systems 422. As discussed above, the EG supply system 78 includes an exhaust gas extraction system 80 and an EG treatment system 82. Exhaust gas extraction system 80 receives exhaust gas 42 from one or more extraction points 76 along any other location within SEGR gas turbine system 52, EG processing system 54, or turbine-based service system 14. .. The EG treatment system 82 is then subjected to exhaust gas extracted by multiple treatment subsystems 424 such as compression system 426, dehumidification / dehydration system 428, particulate matter removal / filtration system 430, gas separation system 432, and gas purification system 434. Handle 42.
0067The illustrated processing subsystem 424 can be arranged in series, in parallel, or in any combination thereof. The compression system 426 may include one or more rotary compressors, reciprocating compressors, or any combination thereof in one or more compression stages. The dehumidification / dehydration system 428 is a heat exchanger such as one or more heat exchangers, a heat recovery steam generator, a condenser, a centrifugal water gas separator, a filter, a desiccant or other dehydration medium, or any of these. It can contain any combination. Particulate matter removal / filtration system 430 may include one or more inertial force sorters, gravity sorters, filters, or any combination thereof. For example, the filter can include a thin film filter, a water impermeable filter, a cohesive filter, or any combination thereof. The gas separation system 432 can include one or more solvent-based separation systems, which can include one or more absorbers, flash tanks, or any combination thereof. For example, the gas separation system 432 has carbon dioxide (CO) from the exhaust gas 42.<sub>2</sub>) And / or nitrogen (N<sub>2</sub>) Can be configured to separate. According to another embodiment, the gas separation system 432 is CO<sub>2</sub>/ N<sub>2</sub>A separator and / or carbon capture system can be included. The gas purification system 432 can also include one or more solvent-based gas refiners and separate gases from the gas separation system 432 (eg, CO).<sub>2</sub>And / or N<sub>2</sub>) Can be further reduced. For example, one of the separated carbon dioxide (CO)<sub>2</sub>) Is further refined by the gas purification system 434, thereby separating carbon dioxide (CO).<sub>2</sub>) Purity level can be increased. Similarly, the gas purification system 434 has separated nitrogen (N).<sub>2</sub>) Was further purified, thereby separating nitrogen (N).<sub>2</sub>) Can remove all impurities. In certain embodiments, the separated carbon dioxide and the separated nitrogen may have a purity level of at least about 70, 80, 90, 95, 96, 97, 98, 99, or higher volume percent purity. it can. In certain embodiments, the gas separation system 432 can generate a plurality of exhaust gas streams 95, such as a first stream 96, a second stream 97, and a third stream 98. For example, the first stream 96 is CO<sub>2</sub>A rich stream 436 can be included, a second stream 97 can contain an intermediate concentration stream 438, and a third stream 98 can contain CO.<sub>2</sub>A lean stream 440 can be included.
0068One or two or more of these exhaust gas streams 95 can then be transferred to one or more secondary gas treatment systems 442 and / or energy recovery systems 444. For example, the first stream 96 can be migrated to the secondary gas treatment system 446, the second stream 97 can be migrated to the secondary gas treatment system 448, and the third stream 98 can be migrated to the secondary gas treatment system 448. It is possible to move to the next gas treatment system 450. Similarly, the first stream 96 can be migrated to the energy recovery system 452, the second stream 97 can be migrated to the energy recovery system 454, and the third stream 98 can be migrated to the energy recovery system 456. Can be migrated to. Each of the secondary gas treatment systems 442 can include a compression system 458, a dehumidification / dehydration system 460, or any other suitable treatment component. Similarly, in this case, the compression system 458 may include one or more rotary compressors, reciprocating compressors, or any combination thereof arranged in a series or parallel arrangement. The dehumidification / dehydration system 460 includes a water gas separator, condenser, filter, or any combination thereof, thereby removing any moisture remaining in the stream 96, 97, or 98 after compression by the compression system 458. can do. Again, each of the streams 96, 97, and 98 can pass through its own dedicated secondary gas treatment system 442, or two or more of these streams are common secondary gases. The processing system 442 can be shared. After this secondary treatment in system 442, the treated exhaust streams 96, 97, and 98 are then 1 such as hydrocarbon production system 12, pipeline 86, storage tank 88, and / or carbon isolation system 90. Alternatively, it is possible to move to two or more target systems 422. In other words, any one or more of the individual streams 96, 97, and 98 may be one or two or more of the target system 422 independently or as a whole.
0069In the energy recovery system 444, each of the streams 96, 97, and 98 then drives one or more loads 464 to produce one or more turbines or expanders that produce mechanical output 466 and / or electrical output 468. Energy recovery is possible at 462. For example, the load 464 can include one or more generators that produce an electrical output of 468. Again, each one of streams 96, 97, and 98 drives its own turbine or expander 462 independently or as a whole in its own dedicated energy recovery system 452, 454, or 456. can do. This recovered energy can be used to drive other equipment throughout the turbine-based service system 14.
0070FIG. 7 is a schematic representation of one embodiment of compressor section 154 of the gas turbine engine 150. As shown, the compressor section 154 has a casing 490 arranged around one or more combustor 160s, thereby defining a compressor exhaust cavity 492 between the casing 490 and the combustor 160. .. Each combustor 160 includes a head end portion 166 and a combustion portion 168. The combustion portion 168 may include a chamber 494, a first wall or liner 496 arranged around the chamber 494, and a second wall or flow sleeve 498 arranged offset around the first wall 496. it can. For example, the first and second walls 496 and 498 are substantially coaxial with each other and can define a hollow circumferential space or flow passage 500 from the combustion portion 168 to the head end portion 166. The second wall or flow sleeve 498 may include multiple openings or perforations 502, which allow pressurized exhaust gas 170 from the compressor section 152 to flow into the flow passage 500. The exhaust gas 170 then flows through the passage 500 along the liner 496 towards the head end portion 166, as indicated by the arrow 504, which causes the exhaust gas 170 to be fed to the chamber 494. Cool the liner 496 as it flows towards the head end portion 166 (eg, through one or more fuel nozzles 164).
0071In certain embodiments, the liner 496 also includes one or more openings or perforations 506, which allows partial injection of exhaust gas 170 directly into chamber 494, as indicated by arrow 508. can do. For example, the exhaust gas injection 508 can function as a diluent injection, which controls the temperature, pressure, flow rate, gas composition (eg, emission level), or any combination thereof within the chamber 494. Can be configured. Specifically, the exhaust gas injection 508 is a nitrogen oxide (NO).<sub>X</sub>) Emissions can help control the temperature in chamber 494 so that it can be substantially reduced in hot combustion products. One or more additional diluents such as nitrogen, vapors, other inert gases, or additional exhaust gases shall be injected through one or more diluent injectors 510, as indicated by arrow 512. Can be done. At the same time, the exhaust gas injection 508 and the diluent injection 512 can be controlled to adjust the temperature, the concentration level of emissions, or other properties of the hot combustion gas flowing through the chamber 494.
0072At the end of the head 166, one or more fuel nozzles 164 are exhaust gas 170, oxidizer 68, fuel 70, and one or more diluent 514 (eg, exhaust gas, steam, nitrogen, etc.). An active gas (or any combination thereof) can be sent to chamber 494 for combustion. For example, each combustor 160 includes one, two, three, four, five, six, seven, eight, or more fuel nozzles 164 configured as diffuse fuel nozzles and / or premixed fuel nozzles, respectively. be able to. For example, each fuel nozzle 164 can deliver oxidant 68, fuel 70, diluent 514, and / or exhaust gas 170 to chamber 494 as a premix or independent stream, which can generate flame 516. A premixed stream of oxidant 68 and fuel 70 results in a premixed flame, while a separate stream of oxidant 68 and fuel 70 results in a diffuse flame.
0073The control system 100 is coupled to one or more fluid supply systems 518, which are pressure, temperature, flow rate, and / or oxidizer 68, fuel 70, diluent 514, and / or exhaust gas 170. Control the air-fuel mixture. For example, control system 100 controls equivalent ratios, emission levels (eg, carbon monoxide, nitrogen oxides, sulfur oxides, unburned hydrocarbons, hydrogen, and / or oxygen), output, or any combination thereof. Therefore, the flow of oxidizer 68, fuel 70, diluent 514, and / or exhaust gas 170 can be controlled independently. During operation, the control system 100 can control the fluid supply system 518 to increase the flow of oxidant 68 and fuel 70 while maintaining substantially quantitative combustion, or the control system 100 The fluid supply system 518 can be controlled to reduce the flow of oxidant 68 and fuel 70 while maintaining substantially quantitative combustion. The control system 100 provides these increases in the flow rates of oxidant 68 and fuel 70 in incremental steps (eg, 1, 2, 3, 4, 5, or more steps), continuously, or in any combination thereof. Or each of the reductions can be carried out. In addition, the control system 100 provides a fuel-rich mixture of oxidizer 68 and fuel 70, a fuel lean mixture, or any other mixture within chamber 494, thereby providing low oxygen concentration, high oxygen concentration, or any of these. Control the fluid supply system 518 to produce hot combustion products or exhaust gas 520 with other suitable oxygen concentrations, unburned hydrocarbons, carbon monoxide, nitrogen oxides, sulfur oxides, and others. The flow of oxidizer 68 and fuel 70 can be increased or decreased. While controlling the flow of the oxidant 68 and the fuel 70, the control system 100 also controls the fluid supply system 518 to control the diluent 514 (eg, steam, exhaust, nitrogen, or any other inert gas). The temperature of the hot combustion product 520, which increases or decreases the flow of the gas, thereby passing the chamber 494 towards the turbine section 156.
0074The control system 100 can also control the EG supply system 78 including the EG extraction system 80 and the EG processing system 82. For example, the control system 100 can selectively open or close one or more valves 522 located along the extraction line 524 between the combustor section 154 and the EG extraction system 80. The control system 100 selectively opens or closes these valves 522 to increase or decrease the flow of the exhaust gas 42 to the EG extraction system 80, and at the same time, to increase or decrease the flow of the exhaust gas to the EG extraction system 80. Exhaust gases can also be selectively extracted from different locations resulting in different temperatures and / or pressures. The control system 100 can also control one or more valves 526 arranged along the pipeline 528 leading to the ventilation system 530. For example, the control system 100 can selectively open the valve 526 to vent a portion of the exhaust gas into the atmosphere through the ventilation system 530, thereby reducing the pressure in the EG supply system 78.
0075As discussed above, each combustor 160 in compressor section 154 can include one or more fuel nozzles 164, the fuel nozzles 164 being configured as premixed fuel nozzles and / or diffusion fuel nozzles. be able to. For example, FIGS. 8, 9, and 10 show an embodiment of a fuel nozzle 164 configured as a premixed fuel nozzle 550 that can be actuated to generate premixed flames 516, 552, while FIGS. 11-16 show. , An embodiment of a fuel nozzle 164 configured as a diffuse fuel nozzle 554 that can be actuated to generate diffuse flames 516, 556. These fuel nozzles 550 and 554 can be used alone or in any combination with each other in each of the combustors 160, as discussed in more detail below with reference to FIG. For example, each combustor 160 may include only the premixed fuel nozzle 550, only the diffusion fuel nozzle 554, or any combination of both the premixed fuel nozzle 550 and the diffusion fuel nozzle 554.
0076The premixed fuel nozzle 550 has various configurations to completely or partially premix the oxidant 68 and the fuel 70, while at the same time exhaust gas 170, vapor, nitrogen, or any other suitable non-compliance. One or more diluents 514, such as active gas, can be optionally premixed. FIG. 8 is a schematic representation of one embodiment of a premixed fuel nozzle 550 having a mixing portion 558 coupled to an injection portion 560. The mixing portion 558 includes at least one mixing chamber 562 surrounded by at least one enclosure 564, while the injection portion 560 includes at least one injection passage 566 surrounded by at least one conduit 568. For example, enclosure 564 of mixing portion 558 may include one or more conduits, injection holes, swirl vanes, flow blockers, or other structures to facilitate mixing between oxidant 68 and fuel 70. it can. The mixing portion 558 also receives one or more streams of diluent 514, such as exhaust gas 170, steam, nitrogen, or another inert gas, thereby mixing diluent 514 with oxidant 68 and fuel 70. be able to. When the oxidant 68 and the fuel 70 are sufficiently mixed in the mixing chamber 562, the premixed fuel nozzle 550 sends the fuel oxidant mixture through the inlet 566 to at least one outlet 570. The mixture from oxidant 68 and fuel 70 (and optionally one or more diluents 514) can then be ignited to create a premix flame 552. In certain embodiments, control system 100 selectively controls fluid supply system 518 to increase or decrease the flow of oxidant 68 and fuel 70 (and optionally one or more diluents 514). This allows the equivalent ratio, the emission level produced by the premixed flame 552, the output of the gas turbine engine 150, or any combination thereof to be adjusted. In certain embodiments, the illustrated premixed fuel nozzle 550 does not premix the oxidant 68 and the fuel 70 with any diluent, but rather One or more diluents (eg, exhaust gas, vapor, nitrogen, or another inert gas) can be provided after the combustion point and / or downstream from the premixed flame 552. In this way, the flow of oxidant 68 and fuel 70 is controlled independently, providing more precise control of the fuel / oxidant ratio, thereby providing temperature and emissions (eg NO).<sub>X</sub>It can help achieve stoichiometric combustion to improve flame stability while also using downstream diluents for control of emissions).
0077FIG. 9 is a schematic view of one embodiment of the premixed fuel nozzle 550 having a multi-stage configuration of the mixing portion 558. As shown, the mixing portion 558 includes first and second mixing chambers 580 and 582, which are defined by the first and second enclosure portions 584 and 586 of the enclosure 564. The first and second mixing chambers 580 and 582 are shown in series arrangement, while another embodiment of the mixing portion 558 arranges the first and second mixing chambers 580 and 582 in parallel arrangement. Can be done. The mixing portion 558 can also include additional mixing chambers in combination with the first and second mixing chambers 580 and 582. For example, the mixing portion 558 may include 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, or more mixing chambers in series, in parallel, or a combination thereof. it can. Each mixing chamber 580 and 582 can include one or more mixing devices such as swirl vanes, flow blockages, winding paths, increased or decreased diameter passages, or any combination thereof. During operation, the mixing portion 558 receives one or more streams of oxidant 68, fuel 70, and one or more diluents 514 from the fluid supply system 518. Similarly, in this case, the diluent 514 can contain exhaust gas 170, vapor, nitrogen, or one or more other inert gases. Each mixing chamber 580582 can receive and mix two or more different fluids from the fluid supply system 518. For example, the first mixing chamber 580 can receive and mix one or more streams of oxidant 68 and fuel 70, while the second mixing chamber 582 can receive and mix oxidant 68 and diluent 514 or fuel. One or more streams of 70 and diluent 514 can be received and mixed. In other words, the first and second mixing chambers 580 and 582 are two or more, or two or more different fluid stories of the same fluid stream from the fluid supply system 518. Can be received and mixed. In this way, the first and second mixing chambers 580 and 582 sequentially mix various fluids from the fluid supply system 518 and then inject the air-fuel mixture for delivery to chamber 494 of the combustor 160. Can be turned inside the 566. When the mixture of oxidizer 68, fuel 70, and one or more diluents 514 flows through the outlet 570 of the inlet 566, the mixture is formed by igniting the premixed flame 552. Similarly, in this case, the control system 100 selectively controls the fluid supply system 518 to increase, decrease, or maintain the flow of the oxidant 68, the fuel 70, and one or more diluents 514. This allows the equivalent ratio, emission level, output of the gas turbine engine 150, or any combination thereof to be adjusted.
0078FIG. 10 is a schematic representation of one embodiment of a premixed fuel nozzle 550 having a stage mixing portion 558 with a parallel mixing section 590 in series with a swirling section 592. The parallel mixing section 590 includes first and second mixing chambers 580 and 582, as discussed above with reference to FIG. 9, and the first and second mixing chambers 580 and 582 are swirling sections 592. They are arranged in parallel with each other on the upstream side from. The swirling section 592 includes an inner conduit or hub 594, an outer conduit 596 arranged around the inner conduit 594, and a plurality of swirl vanes 598 extending radially between the inner conduit 594 and the outer conduit 596. Each of the swirl vanes 598 can be tilted or curved so that the fluid flow swirls around the longitudinal axis 602 of the premixed fuel nozzle 550 in the circumferential direction 600. The inner conduit 594 defines the inner passage 604, the outer conduit 596 defines the outer passage 606, and each swirl vane 598 defines the radial passage 608. One or more of the swirl vanes 598 also include multiple injection portions 610, which can be placed directly at the rear end of each swirl vane 598 or downstream from it.
0079In the illustrated embodiment, the fluid supply system 518 sends one or more streams of oxidant 68 and diluent 514 to the first mixing chamber 580 and at the same time one or more of fuel 70 and diluent 514. Is fed to the second mixing chamber 582. The first mixing chamber 580 substantially mixes the flow of oxidant 68 and diluent 514 and then air-fuel mixture in the outer passage 606 between the inner and outer conduits 594 and 596, as indicated by arrow 612. To send. The mixture 614 of the oxidant 68 and the diluent 514 then flows towards the plurality of swirl vanes 598 in the swirling section 592, where the swirl vanes 598 are axial along the air-fuel mixture 614, as indicated by the arrow 600. Swirl around 602.
0080At the same time, the second mixing chamber 582 sends the premix flow of fuel 70 and diluent 514 to the inner passage 604 defined by the inner conduit 594, as indicated by arrow 616. The air-fuel mixture 618 of fuel 70 and diluent 514 then flows longitudinally along the inner passage 604 to a plurality of swirl vanes 598, as indicated by arrow 620. Upon reaching the plurality of injection ports 610, the air-fuel mixture 618 of fuel 70 and diluent 514 then flows through the injection portion 610 into the outer passage 606, as indicated by arrow 622. The two mixtures (ie, premixed oxidant and diluent flow 614 and premixed fuel and diluent flow 622) are then further mixed in the infusion passage 566, as indicated by arrow 624. The mixture 624 of the oxidant 68, the fuel 70, and the diluent 514 then exits the premixed fuel nozzle 550 through the outlet 570 and then ignites to form the premixed flame 552. Similarly, in this case, the control system 100 selectively controls the fluid supply system 518 to independently control the flow of the oxidant 68, the fuel 70, and the diluent 514, thereby the equivalent ratio of the gas turbine engine 150. , Emission level, output, or any combination thereof can be increased, decreased, or maintained.
0081FIG. 11 is a schematic representation of one embodiment of a diffusion fuel nozzle 554 having a plurality of independent passages 640 for feeding the oxidant 68 and the fuel 70 to the chamber 494 of the combustor 160. The independent passage 640 can include a plurality of concentric circular passages, a central passage surrounded by a plurality of peripheral passages, or any combination thereof. In the illustrated embodiment, the independent passage 640 includes one or more fuel outlets 642 and one or more oxidant passages 644. For example, the illustrated fuel passage 642 is a central fuel passage surrounded by an inner conduit 646, whereas one or more oxidant passages 644 are located between the inner conduit 646 and the outer conduit or structure 648. It is an outer oxidizer passage. According to another embodiment, the oxidant passage 644 is a single cyclic oxidant passage or a plurality of discrete oxidations arranged circumferentially around the fuel passage 642 between the inner and outer conduits 646 and 648. Can include agent passages. In these embodiments, the oxidizer and fuel passages 642 and 644 remain isolated from each other along the overall length of the diffusion fuel nozzle 554. The inner and outer conduits 646 and 648 can function as isolation walls, which maintain the separation between the oxidant 68 and the fuel 70. The fuel passage 642 terminates at the fuel outlet 650 and one or more oxidant passages 644 terminate at one or more oxidant outlets 652. These fuel and oxidizer outlets 650 and 652 are located along the common plane or downstream end 654 of the diffusion fuel nozzle 554, thereby oxidant 68 until after injection from the fuel nozzle 554 of the combustor 160 into chamber 494. And the mixing of fuel 70 can be delayed.
0082When the oxidizer 68 and the fuel 70 mix or diffuse with each other in chamber 494, the diffuse flame 556 forms as indicated by the contour or boundary 656. Contour 656 can represent a diffusion wall or a flame wall, where the oxidizer 68 and the fuel 70 are mixed and burned in a substantially stoichiometric manner (eg, substantially stoichiometric combustion). .. In other words, the contour or boundary 656 can represent a stable flame wall of the diffuse flame 556, with an equivalent ratio of about 1.0 or about 0.95 to 1.05. Similar to the premixed fuel nozzle 550 discussed above with reference to FIGS. 8-10, the diffusion fuel nozzle 554 is controlled by the control system 100 to control the equivalent ratio, exhaust emissions, power of the gas turbine engine 150, or these. Any combination can be changed. For example, the illustrated control system 100 selectively controls the fluid supply system 518 to increase, decrease, or maintain the flow of oxidant 68 and fuel 70 in response to sensor feedback 130.
0083FIG. 12 is a schematic representation of one embodiment of a diffusion fuel nozzle 554 having a plurality of independent passages 670 with an injection portion 672 and a mixing portion 674. Mixing section 674, de may include one or more inner mixing chamber 676 and one or more outer mixing chamber 678 as possible. For example, the inner mixing chamber 676 can be a fuel / diluent mixing chamber, which is configured to mix one or more streams of fuel 70 and diluent 514. The outer mixing chamber 676 can include one or more oxidant / diluent mixing chambers, which are configured to mix one or more streams of oxidant 68 and diluent 514. Each of these mixing chambers can include surrounding structures such as outer enclosures or conduits. For example, the mixing chamber 676 can be surrounded by an inner conduit or enclosure 680, while the mixing chamber 678 can be surrounded by an outer conduit or enclosure 682. In certain embodiments, the mixing chamber 678 can be encapsulated between the inner and outer conduits 680 and 682.
0084Similarly, injection portion 672 includes one or more fuel-diluent passages 684 and one or more oxidant-diluent passages 686. Each fuel-diluent passage 684 is fluidly coupled to one or more of the mixing chamber 678, while each of the oxidizer-diluent passages 686 is fluidly coupled to one or more of the mixing chamber 678. Will be done. The fuel-diluent passage 684 can be surrounded by the inner conduit 688, while one or more oxidant-diluent passages 686 can be surrounded by the outer conduit 690. For example, the illustrated fuel-diluent passage 684 can be a central fuel-diluent passage 684, which is surrounded by one or more oxidant-diluent passages 686. For example, the inner and outer conduits 688 and 690 can be concentric annular conduits, which define passages 684 and 686 in a coaxial or concentric annular arrangement. However, the fuel-diluent passage 684 can represent a single central passage or multiple separate passages located within the inner conduit 688. Similarly, the oxidizer-diluent passage 686 can represent a single annular passage or multiple discrete passages spaced apart from each other in the circumferential direction around the fuel-diluent passage 684. Can remain isolated from each other by the inner and outer conduits 688 and 690. In certain embodiments, the inner vessels 680 and 688 form a single continuous inner conduit and the outer vessels 682 and 690 form a single continuous outer conduit.
0085During operation, control system 100 selectively controls fluid supply system 518 to increase, decrease, or maintain the flow of oxidant 68 and diluent 514 to mixing chamber 676, and mixing chamber 676 is an air-fuel mixture. Mix fuel 70 and diluent 514 before flowing through the fuel-diluent passage 684. Similarly, control system 100 selectively controls fluid supply system 518 to increase, decrease, or maintain the flow of oxidant 68 and diluent 514 to one or more mixing chambers 678, and mixing chamber 678. Mixes oxidizer 68 and diluent 514 before feeding the mixture to one or more oxidant-diluent passages 686. The diffusion fuel nozzle 554 then flows the fuel-diluent mixture 698 separately to the outlet 692 along the passage 684, while simultaneously flowing one or more oxidizer-diluent mixture 700 along the passage 686. Flow to exit 694. Similar to the embodiment of FIG. 11, outlets 692 and 694 are arranged along the common plane or downstream end 696 of the diffusion fuel nozzle 554, thereby allowing the oxidizer-diluent mixture 700 and passage 684 in passage 686. Isolation can be maintained between the fuel-diluent mixture 698. This isolation delays mixing between oxidant 68 and fuel 70 down to the downstream side of common plane 696.
0086When the fuel-diluent mixture 698 and the oxidizer-diluent mixture 700 flow from the diffusion fuel nozzle 554 into chamber 494 of the combustor 160, the mixture 698 and 700 generally diffuse into each other, diffusing the diffusion flame 556. Burn along a contour or boundary 702 where a wall or flame wall can be defined. Similarly, in this case, the control system 100 selectively controls the fluid supply system 518 to independently control the flow of the oxidant 68, the fuel 70, and the diluent 514 for each of the mixing chambers 676 and 678. This allows control of mixing within each of the mixing chambers 676 and 678, while also controlling diffusion and combustion within chamber 494 of the combustor 160. For example, control system 100 selectively controls the fluid supply system 518 to the ratio of oxidant 68 to fuel 70, the ratio of diluent 514 to the combined flow of oxidant 68 and fuel 70, a mixture of one or more. The ratio of oxidizer 68 to diluent 514 in each of chamber 678 and corresponding passage 686, and the ratio of fuel 70 to diluent 514 in each of one or more mixed chambers 676 and corresponding passage 684 can be adjusted. it can. Therefore, the control system 100 adjusts each of these ratios, flow rates, temperatures, and fluid compositions (eg, composition of oxidant 68, fuel 70, and diluent 514) to the equivalent ratio of gas turbine engine 150. Exhaust emissions and output can be adjusted.
0087FIG. 13 is a schematic view of one embodiment of the diffusion fuel nozzle 554 showing the plurality of independent passages 720. The illustrated passage 640 includes a fluid A passage 722, one or more fluid B passages 724, and one or more fluid C passages 726. The fluid A passage 722 can be separated or isolated from one or more fluid B passages 724 by a conduit or structure 728, and one or more fluid B passages 724 are one or two by a conduit or structure 730. It can be separated from the above fluid C passages 726, and one or more fluid C passages 726 can be surrounded or supported by an outer conduit or structure 732.
0088For example, as shown in FIG. 14, fluid passages 722, 724, and 726 can be arranged concentrically, conduit 728 surrounds fluid A passage 722 as a central fluid passage, and fluid B passage 724 is conduit 728. And 730, the fluid C passage 726 is placed between the conduits 730 and 732. Similarly, in this case, the conduits 728, 730, and 732 can be arranged concentrically so that the fluid B passage 724 and the fluid C passage 726 each represent a continuous annular passage.
0089However, the diffusion fuel nozzle 554 can arrange passages 722, 724, and 726 in other arrangements such as discrete passages, as shown in FIG. In the embodiment of FIG. 15, fluid A passage 722 represents a central fluid passage, whereas fluid B passage 724 and fluid C passage 726 represent a plurality of discrete passages spaced apart from each other within the fuel nozzle 554. .. For example, the fluid B passage 724 is arranged around the central fluid A passage 722, spaced apart from each other in the circumferential direction, 2, 3, 4, 5, 6, 7, 8, or more discretes. It can include a fluid passage. Similarly, the fluid C passage 726 may include a plurality of discrete passages arranged around the fluid B passage 724, spaced from each other in the circumferential direction. For example, the fluid B passage 724 can be arranged in the first ring or circular pattern of the passage 724, while the fluid C passage 726 can be arranged in the second ring or circular pattern of the passage 726.
0090In any of these configurations, the diffusion fuel nozzle 554 of FIG. 13 has fluid A734 through fluid A passage 722, fluid B736 through one or more fluid B passages 724, and one or more fluid C. It is configured to flow through passage 726 and fluid B738 separately. Each of these fluids 734, 736, and 738 can contain one or more fluids such as oxidant 68, fuel 70, and diluent 714. However, the fluids 734, 736, and 738 do not mix either the oxidizer 68 or the fuel 70 in the diffusion fuel nozzle 554, causing the fluid to flow from the combustor 160 openings 740, 742, and 744 into the chamber 494. Mixing between oxidant 68 and fuel 70 can be delayed until released to. Similarly, in this case, these openings 740, 742, and 744 can be arranged along the common plane or downstream end 746 of the diffusion fuel nozzle 554. The various fluids are then mixed and burned to form a diffuse flame 556, as discussed above. Indication 2 below shows some possible non-limiting examples of fluids A, B, and C, which can be used with the diffusion fuel nozzles 554 of FIGS. 13-15.
0091Table 2<img id="000004" he="57" wi="143" file="JP2016502016A_D0001.tif" img-format="tif" img-content="drawing" />
0092As shown above, the diffusion fuel nozzle 554 allows various combinations of fluids (eg, oxidizer 68, fuel 70, and diluent 514) to pass through passages 722, 724, and 726 for the generation of diffusion flame 556. Can be shed. Similarly, in this case, the oxidant 68 can include oxygen, ambient air, oxygen-enriched air, oxygen-deficient air, a mixture of nitrogen and oxygen, or any combination thereof. The fuel 70 can include liquid fuels and / or gas fuels, gas fuels such as natural gas, syngas, or any other fuel described herein. Diluent 514 can include exhaust gas 170, vapor, nitrogen, or another inert gas, or any combination thereof. Table 2 depicts some possible examples of fluids, but any combination of fluids can be used with the diffusion fuel nozzle 554 in FIGS. 13-15. In addition, in the illustrated embodiment, none of the fuels 70 mixes with the oxidizer 68 in the diffusion fuel nozzle 554, while in other embodiments small amounts (eg, 1, 2, 3, 4, 5, 6, 7, 8, 9, or less than 10 volume percent of oxidizer 68 with fuel 70 or a small amount (eg, less than 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10 volume percent) The fuel 70 can be mixed with the oxidant 68.
0093FIG. 16 is a schematic representation of one embodiment of a combustor section 154 having one of the diffusion fuel nozzles 554 disposed within the combustor 160. Similar to the diffusion fuel nozzle 554 shown in FIGS. 13 to 15, the diffusion fuel nozzle 554 of FIG. 16 has a fluid A passage 722 surrounded by a conduit 728, a fluid B passage 724 surrounded by a conduit 730, and a conduit 732. Includes a fluid C passage 726 surrounded by a fluid D passage 760 surrounded by an outer conduit or structure 762. The fluid D passage 760 receives the fluid D764 from the fluid supply system 518 and sends the fluid D764 to the chamber 494 through one or more outlets 766. Passages 722, 724, 726, and 760 have outlets 740, 742, 744, and 766, respectively, located along the common plane or downstream end 746 of the diffusion fuel nozzle 554, which allows the fluid to flow into chamber 495. Flows of fluids 734, 736, 738, and 764 can be isolated until reaching. In this way, the diffusion fuel nozzle 554 promotes the formation of the diffusion flame 556. Each of the fluids 734, 736, 738, and 764 is diluted 1 or 2 or more with oxidizer 68, fuel 70, and exhaust gas 170, vapor, nitrogen, and / or one or more other inert gases. Agent 514 can be included. However, the fluid passages 722, 724, 726, and 760 do not mix with any of the oxidizer 68 and fuel 70 in the diffusion fuel nozzle 554, thereby allowing the oxidizer 68 and fuel 70 to reach chamber 494. Isolation can be promoted. The oxidant 68 and the fuel 70 can flow through each of the independent fluid passages 722, 724, 726, and 760, which are separately or partially premixed with one or more of the diluent 514. Similar to the previous embodiment, the control system 100 selectively controls the fluid supply system 518 to increase, decrease, or maintain the flow of each fluid 734, 736, 738, and 764, thereby the gas turbine engine. Fluid flow ratio, equivalence ratio, emission of 150 fluids
0094The illustrated combustor 160 of FIG. 16 also includes a diluent injection system 770 arranged along the combustion portion 168 of the combustor 160, resulting in one or more diluents (eg, exhaust gas 170, steam). , Nitrogen, or other inert gas) is injected into chamber 494 and the temperature, pressure, flow rate, gas composition (eg, emission level), or of the hot combustion product 772 formed by the diffusion flame 556, or You will be able to control some combination of these. For example, the diluent injection system 770 has a plurality of perforations 506 openings located in the first wall or liner 496 and a plurality of extending through the first and second walls 496 and 498 to chamber 494 of the combustor 160. Diluent injector 510 and can be included. During operation, the openings or perforations 506 can be configured to inject fluid E774, such as exhaust gas 170, as indicated by arrow 508. Diluent injector 510 can be configured to inject fluid F776 and / or fluid G778 into chamber 494, as indicated by arrow 512. For example, the fluid F776 and the fluid G778 can include an additional exhaust gas 170, vapor, nitrogen, one or two or more other inert gases, or any combination thereof. These injected diluents 508 and 512 are configured to control the temperature, pressure, flow rate, gas composition (eg, emission level), or any combination thereof of the hot combustion products 772 resulting from the diffusion flame 556. can do. In certain embodiments, control system 100 selectively controls fluid supply system 518 to increase, decrease, or maintain the flow of various fluids 734,736,738,764,774,776, and 778. This allows control of the ratio of oxidant 68 to fuel 70, the ratio of oxidant 68 and one or more diluents 514 to fuel 70, or any combination thereof. These control adjustments of the fluid are then the equivalent ratio, emission level, and output of the gas turbine engine 150. Can be changed. Table 3 below shows some possible non-limiting examples of fluids A, B, C, D, E, F, and G, which are the diffusion fuel nozzle 554 and the combustor 160 in FIG. Can be used in.
0095Table 3<img id="000005" he="88" wi="147" file="JP2016502016A_D0001.tif" img-format="tif" img-content="drawing" />
0096As shown above, the diffusion fuel nozzle 554 and the combustor 160 are in various combinations through passages 722, 724, 726, and 760, openings 506, and diluent injector 510 for the generation of diffusion flame 556. Fluids (eg, oxidizer 68, fuel 70, and diluent 514) can flow. Similarly, in this case, the oxidant 68 can include oxygen, ambient air, oxygen-enriched air, oxygen-deficient air, a mixture of nitrogen and oxygen, or any combination thereof. The fuel 70 can include fluid fuels and / or gas fuels such as natural gas, syngas, or any other fuel described herein. Diluent 514 can include exhaust gas 170, vapor, nitrogen, or another inert gas, or any combination thereof. Table 3 depicts some possible examples of fluids, but any combination of fluids can be used with the diffusion fuel nozzle 554 and combustor 160 of FIG. In addition, the illustrated embodiment does not mix any fuel 70 with the oxidant 68 in the diffusion fuel nozzle 554, while the other embodiments are in small amounts (eg, 1, 2, 3, 4, 5). , 6, 7, 8, 9, or less than 10 volume percent oxidizer 68 with fuel 70 or a small amount (eg 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10 volume percent) Less than) fuel 70 can be mixed with oxidant 68.
0097FIG. 17 is a schematic cross-sectional view of the combustor 160 along line 17-17 of FIG. 7, further showing the multiple nozzle configuration of the fuel nozzle 164 and the multiple injector arrangement of the diluent injector 510. The illustrated fuel nozzle 164 includes a fuel nozzle A790, a fuel nozzle B792, a fuel nozzle C794, a fuel nozzle D796, a fuel nozzle E798, a fuel nozzle F800, and a fuel nozzle G802. In the illustrated embodiment, the nozzle 790 is a central fuel nozzle, which is surrounded by fuel nozzles 792, 794, 796, 798, 800 and 802 that remain as outer or peripheral fuel nozzles. The illustrated embodiment includes a single central fuel nozzle 164 and six outer fuel nozzles 164, while other embodiments can include any number of central and outer fuel nozzles. The illustrated fuel nozzle 164 may include one or more of the premixed fuel nozzles 550 and / or the diffusion fuel nozzles 554 shown and described with reference to FIGS. 8-16. For example, all of the fuel nozzles 164 can be configured as premixed fuel nozzles 550, all of the fuel nozzles 164 can be configured as diffusion fuel nozzles 554, or the fuel nozzles 164 can be configured as premixed fuel nozzles 550. And one or more of both diffusion fuel nozzles 554 can be included. The fluid flow to the fuel nozzles 164 can be controlled independently for each fuel nozzle 164, or the fluid flow can be controlled by a group of fuel nozzles 164. For example, the central fuel nozzle 790 can be controlled independently from one or more groups of outer fuel nozzles 792, 794, 796, 798, 800, and 802. According to another embodiment, one or more premixed fuel nozzles 550 can be controlled independently of one or more diffusion fuel nozzles 554. These different control schemes can facilitate different modes of operation, which can be useful in providing quantitative combustion and reducing emissions of exhaust gas 42.
0098As further shown in FIG. 17, the fuel nozzle 164 and the diluent injector 510 are fluidd through multiple fluid supply circuits 810, such as one or more diluent supply circuits 812 and one or more fuel nozzle supply circuits 814. Can be coupled to supply system 518. For example, the diluent supply circuit 812 includes 1, 2, 3, 4, 5, 6, 7, 8, or more independent diluent supply circuits 812, thereby for the diluent injector 510. Various diluent injection modes can be enabled. Similarly, the fuel nozzle supply circuit 814 includes 1, 2, 3, 4, 5, 6, 7, 8, or more independent fuel nozzle supply circuits 814, thereby varying relative to the fuel nozzle 164. Fluid supply mode can be enabled. For example, the fuel nozzle supply circuit 814 can include a first nozzle circuit 816, a second nozzle circuit 818, and a third nozzle circuit 820. Each of these fuel nozzle supply circuits 814 (eg, 816, 818, and 820) has one or more fuel lines, oxidant lines, and / or diluent lines (eg, extraction lines, steam). Pipes, nitrogen pipes, and / or other inert gas pipes) can be included, which are fluidly coupled to at least one fuel nozzle 164. In the illustrated embodiment, the first nozzle circuit 816 is coupled to the first set of fuel nozzles 164 (eg, central fuel nozzle 790) and the second nozzle circuit 818 is the second set of fuel nozzles 164. Coupled to (eg, outer fuel nozzles 794, 798, and 802), the third nozzle circuit 820 is coupled to a third set of fuel nozzles 164 (eg, outer fuel nozzles 792, 796, and 800). .. In some embodiments, the fuel nozzle 164 of each coupled set of one of the nozzle supply circuits 814 is with a fully diffused fuel nozzle, a fully premixed fuel nozzle, or any combination of diffused fuel nozzles and peripheral fuel nozzles. can do. However, any number or combination of fuel nozzles 164 are connected to each fuel nozzle supply circuit 814. It can be fitted and any number of nozzle supply circuits 814 can be coupled to the fuel nozzle 164. Similarly, in this case, the fuel nozzle supply circuit 814 is coupled to the fluid supply system 518, which includes a valve, a flow control valve, and other flow controls, the flow rate of the flow to the fuel nozzle 164 and. The pressure can be controlled.
0099The fluid supply system 518 is then coupled to the control system 100, which uses controller 118 to receive sensor feedback 130 and provide control signal 306 to fluid supply system 518 to activate circuits 812 and 814. Can be controlled. In the illustrated embodiment, controller 118 of system 100 can store and execute stoichiometric control mode 822 and non-stoichiometric control mode 824 (eg, computer instructions or codes associated with them), which are fuels. Lean control mode 826 and fuel rich control mode 828 can be further included. The controller 118 of the system 100 also includes a fluid supply controller 830 (related to eg computer instructions or) including a first fluid circuit controller 832, a second fluid circuit controller 834, and a third fluid circuit controller 836. Code) can be stored and executed. For example, the first fluid circuit controller 832 can be configured to control various flow rates to the first nozzle circuit 816 (eg, oxidant 68, fuel 70, and / or diluent 514). , The second fluid circuit controller 834 can be configured to control various flow rates to the second nozzle circuit 818 (eg, oxidant 68, fuel 70, and / or diluent 514). The third fluid circuit controller 836 can be configured to control various flow rates to the third nozzle circuit 820 (eg, oxidant 68, fuel 70, and / or diluent 514).
0100In certain embodiments, the quantitative control mode 822 changes the flow rate of at least one fuel 70 and at least one oxidant 68 to provide a substantial stoichiometric ratio of fuel 70 to oxidant 68. The non-stoichiometric control mode 824 is configured to vary the flow rate and provide a non-stoichiometric ratio of fuel 70 to oxidant 68. For example, the quantitative control mode 822 can be configured to provide a substantial stoichiometric ratio having an equivalent ratio of about 1.0 or about 0.95 to about 1.05. In contrast, non-stoichiometric control mode 824 is less than about 0.95 or about 1. It can be configured to provide a non-stoichiometric ratio with an equivalent ratio greater than 05. In some embodiments, the control system 100 can be configured to vary the flow rate from the flow rate of the first set to the flow rate of the second set, while the first and second flow rates are mutually exclusive. Different (eg, greater than or less than each other). Controlled changes in flow rate can also involve a transition between quantitative control mode 822 and non-stoichiometric control mode 824, or controlled changes in flow rate are also substantial stoichiometric ratios. Can be accompanied by maintenance. The controlled change in flow rate is also accompanied by a change in the output (or load) of the SEGR gas turbine system 52 from a first output (or first load) to a second output (or second load). The first and second outputs (eg, loads) are different from each other (eg, smaller or larger than each other). For example, a controlled change in power may be accompanied by a controlled change in turbine load, a reduction from the turbine rated load or normal load (eg 100 percent) to a partial load (eg 50 percent). Controlled changes in flow rate may also involve maintaining exhaust gas emissions within one or more target emission ranges, which are carbon monoxide, oxygen, nitrogen oxides, sulfur oxides, etc. It can include unburned hydrocarbons, hydrogen, or any combination thereof. In certain embodiments, one or more target emission ranges can include an oxygen range of less than about 50 ppmv (one millionth volume) and / or a carbon monoxide range of less than about 5000 ppmv. In other embodiments, the one or more target emission ranges include an oxygen range of less than about 10 ppmv and / or a carbon monoxide range of less than about 1000 ppmv.
0101In some embodiments, the control system 100 of the stoichiometric control mode 822 gradually reduces the flow rate (eg, oxidant 68 and fuel 70) among the flow rates of the plurality of sets to multiple outputs (eg, eg, fuel 70). The output (eg, load) of the SEGR gas turbine system 52 is gradually reduced among the full load, the first partial load, the second partial load, etc., and the exhaust gas is within the target emission range of 1 or 2 or more. It is configured to maintain a substantial stoichiometric ratio while maintaining the emissions of. The control system 100 is also configured to transition from the stoichiometric control mode 822 to the non-stoichiometric control mode 824 after the flow rate is gradually reduced, the output is gradually reduced, and the emission is maintained. Can be done. After transitioning from the stoichiometric control mode 822 to the non-stoichiometric control mode 824, the control system 100 shall also be configured to operate in the fuel-rich or lean control mode of the non-stoichiometric control mode 824. Can be done. The control system 100 also operates in a first set of target emission ranges (eg, operating in stoichiometric control mode 822) and a second set of target emission ranges (eg, operating in non-stoichiometric control mode 824). While) can be configured to maintain exhaust emissions within, the target emission ranges of the first and second sets differ from each other. The above embodiment provides some control scenarios for the SEGR gas turbine engine 52, but some control scenarios are performed by the control system 100 with diffusion fuel nozzles, premixed fuel nozzles, or any combination thereof. Please understand that you can do it.
0102FIG. 18 is a graph of exhaust gas recirculation (EGR) flow and gas turbine load 840 to fuel / oxidant ratio 842 for SEGR gas turbine system 52 including diffuse flame activation curve 844 and premixed flame activity curve 846. .. The EGR flow rate by the SEGR gas turbine system 52 is approximately proportional to the load on the gas turbine engine 150, so the Y-axis 840 indicates both the EGR flow rate and the gas turbine load as a whole. In general, the area above and to the left of each curve 844 and 846 represents a region that is unstable for each flame configuration of the SEGR gas turbine system 52. It should be noted that the diffusion flame actuation curve 844 substantially exceeds the premixed flame actuation curve 846, indicating a substantially larger EGR flow rate and load range for the SEGR gas turbine system 52 operating in diffusion combustion. Is. As shown in FIG. 18, the diffusion flame actuation curve 844 can correspond to a combustor 160 equipped with a diffusion fuel nozzle 554, and the exhaust gas (eg, diluent) is the diffusion fuel nozzle after the combustion point. Infused downstream from 554 and / or downstream from diffuse flame 556 generated by nozzle 554. An example of such a diffusion combustion configuration is shown in FIG. In contrast, the premixed flame actuation curve 846 can accommodate a combustor 160 equipped with a premixed fuel nozzle 550, with oxidizer 68, fuel 70, and diluent 514 (eg, exhaust gas). Premixed before the combustion point (ie, on the distillation side from the premixed flame 552). Again, the diffusion flame actuation curve 844 shows a much higher EGR flow through the SEGR gas turbine system 52, which is also a larger CO for use in the target system 422.<sub>2</sub>Means the generation of. The SEGR gas turbine system 52 operating in the diffusion combustion configuration described above may also substantially reduce oxygen and carbon monoxide emissions. These emission reductions are believed to be at least partially due to the independent control of the flow of oxidant 68, fuel 70, and diluent 514 (eg, exhaust gas). The various configurations of the diffusion fuel nozzle 554 and the diluent injection (eg, the diluent injection system 770 of FIG. 16) are the operable range of the gas turbine load for use in the target system 422, such as the hydrocarbon production system 12. It is believed that the processing capacity of the exhaust gas and the output of the exhaust gas 42 (eg, stream 95) can be substantially increased.
0103(Supplemental information) By way of example, the following provisions are provided as a further explanation of this disclosure.
0104Embodiment 1. The first flow comprises a first and a second passage for separately injecting each first and second flow into the turbine combustor chamber to generate a diffuse flame, the first flow being the first. A second stream is driven by a turbine combustor containing a first diffusion fuel nozzle containing a fuel and a first diluent and a combustion product from a diffusion flame in the turbine combustor. A system including a turbine and an exhaust gas compressor configured to compress the exhaust gas and send the exhaust gas from the turbine to a turbine combustor along an exhaust gas recirculation path.
0105Embodiment 2. The system according to Embodiment 1, wherein the first diluent comprises a portion of exhaust gas, vapor, nitrogen, another inert gas, or a combination thereof.
0106Embodiment 3. The system according to any of the above embodiments, wherein the first diluent comprises a portion of the exhaust gas.
0107Embodiment 4. The system according to any of the above embodiments, wherein the first diluent comprises vapor.
0108Embodiment 5. The system according to any of the above embodiments, wherein the first diluent comprises an inert gas.
0109Embodiment 6. The system according to any of the above embodiments, wherein the inert gas comprises nitrogen.
0110Embodiment 7. The first and second passages have their respective first and second outlets located along the downstream end of the first diffusion fuel nozzle, with the first and second passages. , The system according to any of the aforementioned embodiments, isolated from each other along a first diffusion fuel nozzle.
01118. The system according to any of the aforementioned embodiments, wherein the first and second passages are arranged concentrically.
0112Embodiment 9. The system according to any of the aforementioned embodiments, wherein the first passage extends around the second passage.
0113Embodiment 10. The system according to any of the aforementioned embodiments, wherein the second passage extends around the first passage.
0114Embodiment 11. The first diffusion fuel nozzle includes a third passage separate from the first and second passages, and the third passage chambers the third flow from the first and second flows. The system according to any of the aforementioned embodiments, wherein the third stream is configured to be injected separately into a second fuel, a second diluent, or a second oxidant.
0115Embodiment 12. The system according to any of the aforementioned embodiments, wherein the third stream comprises a second fuel and the first and second fuels are the same as each other.
0116Embodiment 13. The system according to any of the aforementioned embodiments, wherein the third stream comprises a second fuel and the first and second fuels are different from each other.
0117Embodiment 14. The system according to any of the aforementioned embodiments, wherein the third stream comprises a second fuel and a second diluent.
0118Embodiment 15. As described in any of the aforementioned embodiments, wherein the first and second fuels are the same as each other, or the first and second diluents are the same as each other, or a combination thereof. system.
0119Embodiment 16. The system according to any of the above embodiments, wherein the first and second fuels are different from each other, or the first and second diluents are different from each other, or a combination thereof.
0120Embodiment 17. The first and second fuels are different from each other, the first and second diluents are the same as each other, or the first and second fuels are the same as each other, the first and second The system according to any of the aforementioned embodiments, wherein the diluents of 2 are different from each other.
0121Embodiment 18. The system according to any of the above embodiments, wherein the first and second fuels contain a portion of exhaust gas.
0122Embodiment 19. The first diffusion fuel nozzle includes a fourth passage separate from the first, second, and third passages, and the fourth passage is the first, second, and third passages. Any of the aforementioned implementations in which a fourth stream is configured to be injected into the chamber separately from the aisle, the fourth stream containing a third fuel, a third diluent, or a third oxidant. The system described in the form.
012320. The system according to any of the aforementioned embodiments, wherein the turbine combustor comprises a second diffusion fuel nozzle.
012421. The system according to any of the aforementioned embodiments, wherein the turbine combustor comprises a first premixed fuel nozzle.
0125Embodiment 22. The system according to any of the aforementioned embodiments, wherein the turbine combustor comprises a diluent injection system located downstream from the first diffusion fuel nozzle.
0126Embodiment 23. A diluent injection system injects a portion of exhaust gas, vapor, nitrogen, or another inert gas, or a combination thereof, from a first diffusion fuel nozzle into a downstream turbine combustor chamber. The system according to any of the aforementioned embodiments configured as
0127Embodiment 24. The aforementioned diluent injection system comprises a plurality of openings in the turbine combustor liner, the plurality of openings comprising injecting a portion of the exhaust gas into the turbine combustor chamber as described above. The system according to any embodiment.
0128Embodiment 25. The turbine combustor was placed between the first wall placed around the chamber, the second wall placed around the first wall, and the first and second walls. The system according to any of the aforementioned embodiments, comprising an exhaust gas passage, wherein the diluent injection system comprises a plurality of diluent injectors extending through the first and second walls of the turbine combustor.
0129Embodiment 26. In any of the aforementioned embodiments, wherein the plurality of diluent injectors are configured to inject a portion of the exhaust gas, stream, nitrogen, or another inert gas into the chamber of the turbine combustor. Described system.
0130Embodiment 27. The system according to any of the aforementioned embodiments, comprising a first catalyst unit arranged along an exhaust gas recirculation path.
0131Embodiment 28. The system according to any of the aforementioned embodiments, wherein the first catalyst unit is configured to control the concentration levels of carbon monoxide, carbon dioxide, and unburned hydrocarbons in the exhaust gas.
0132Embodiment 29. The first catalyst unit is an oxidation catalyst, carbon monoxide catalyst, aluminum oxide, zirconium oxide, silicone oxide, titanium oxide, platinum oxide, palladium oxide, cobalt oxide, or mixed metal. The system according to any of the above embodiments comprising oxides, or combinations thereof.
0133Embodiment 30. The system according to any of the aforementioned embodiments, wherein the oxidation catalyst unit is configured to drive an oxidation reaction using exhaust gas and an oxidant fuel.
0134Embodiment 31. The system according to any of the aforementioned embodiments, comprising a control system configured to regulate the flow of oxidant fuel to control the oxidation reaction.
0135Embodiment 32. The control system is configured to regulate the flow of oxidant fuel in response to sensor feedback, and the sensor feedback is oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or these. The system according to any of the aforementioned embodiments, comprising gas composition feedback indicating any combination of.
0136Embodiment 33. The system according to any of the aforementioned embodiments, comprising a first heat recovery unit arranged along an exhaust gas recirculation path.
0137Embodiment 34. The system according to any of the aforementioned embodiments, comprising a catalyst having a first catalyst unit and a first heat recovery unit and a heat recovery system.
0138Embodiment 35. The system according to any of the above embodiments, wherein the first catalyst unit is located upstream, downstream, or integrated with the first heat recovery unit.
0139Embodiment 36. The system according to any of the aforementioned embodiments, comprising a second heat recovery unit arranged along an exhaust gas recirculation path.
0140Embodiment 37. The system according to any of the aforementioned embodiments, comprising a second catalyst unit arranged along an exhaust gas recirculation path.
0141Embodiment 38. The system according to any of the above embodiments, wherein the first heat recovery unit comprises a first heat recovery steam generator.
0142Embodiment 39. The system according to any of the aforementioned embodiments, comprising a first steam turbine coupled to a first heat recovery steam generator.
0143Embodiment 40. The first heat recovery unit includes a first heat recovery steam generator, and the second heat recovery unit includes a second heat recovery steam generator. System.
0144Embodiment 41. Any of the aforementioned embodiments comprising a first steam turbine coupled to a first heat recovery steam generator and a second steam turbine coupled to a second heat recovery steam generator. The system described in.
0145Embodiment 42. The system according to any of the aforementioned embodiments, including a dehumidifying system arranged along an exhaust gas recirculation path.
0146Embodiment 43. The system according to any of the aforementioned embodiments, wherein the dehumidifying system comprises a heat exchanger, a condenser, a water / gas separator, a filter, or a combination thereof.
0147Embodiment 44. The system according to any of the aforementioned embodiments, comprising a particulate matter removal system arranged along an exhaust gas recirculation path.
0148Embodiment 45. The system according to any of the aforementioned embodiments, wherein the particulate matter removal system comprises an inertial force sorter, a gravity sorter, a filter, or a combination thereof.
0149Embodiment 46. The system according to any of the aforementioned embodiments, comprising a booster blower arranged along an exhaust gas recirculation path.
0150Embodiment 47. The system according to any of the aforementioned embodiments, comprising a heat recovery unit, a booster blower, a dehumidifying unit, and a particulate matter removal unit arranged along an exhaust gas recirculation path.
0151Embodiment 48. The system according to any of the aforementioned embodiments, comprising an exhaust gas extraction system configured to extract a portion of the exhaust gas.
0152Embodiment 49. The system according to any of the aforementioned embodiments, including an exhaust gas treatment system configured to treat a portion of the exhaust gas.
015350. The system according to any of the aforementioned embodiments, wherein the exhaust gas treatment system comprises a gas separation system configured to separate a portion of the exhaust gas into a plurality of gas streams.
0154Embodiment 51. Multiple gas streams are carbon dioxide (CO)<sub>2</sub>) Rich first stream and carbon dioxide (CO)<sub>2</sub>) The system according to any of the above embodiments, including a second stream that is lean.
0155Embodiment 52. The first stream is nitrogen (N)<sub>2</sub>) Lean, the second stream is nitrogen (N<sub>2</sub>) The system according to any of the above embodiments, which is rich.
0156Embodiment 53. The gas compression system, dehumidification system, particulate matter removal system, or a combination thereof, wherein the exhaust gas treatment system is configured to receive at least one of the first or second streams. The system according to any embodiment.
0157Embodiment 54. The system according to any of the aforementioned embodiments, wherein the exhaust gas treatment system comprises a gas purification system configured to purify at least one of a plurality of gas streams.
0158Embodiment 55. A target system comprising a target system configured to receive at least one of a plurality of streams, the target system being a hydrocarbon production system, an underground reservoir, a carbon isolation system, a pipeline, a storage tank, or these. The system according to any of the above embodiments, comprising any combination.
0159Embodiment 56. The system according to any of the aforementioned embodiments, wherein the exhaust gas treatment system comprises a compression system configured to compress a portion of the exhaust gas.
0160Embodiment 57. The system according to any of the aforementioned embodiments, wherein the exhaust gas treatment system comprises a dehumidifying system and / or a particulate matter removal system.
0161Embodiment 58. The system according to any of the aforementioned embodiments, comprising a control system that adjusts one or more operating parameters in response to sensor feedback to control the exhaust gas equivalent ratio or emission level.
0162Embodiment 59.1 The system according to any of the aforementioned embodiments, wherein one or more operating parameters include an oxidant flow rate and / or a fuel flow rate for a turbine combustor.
0163Embodiment 60. The system according to any of the aforementioned embodiments, wherein the control system is configured to maintain an equivalent ratio between about 0.95 and 1.05.
0164Embodiment 61. Described in any of the aforementioned embodiments, wherein the sensor feedback comprises gas composition feedback associated with oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof. system.
0165Embodiment 62. A control system is coupled to a plurality of sensors configured to obtain sensor feedback, the plurality of sensors being exhaust gas recirculation paths, turbine combustors, turbines, exhaust gas compressors, or a combination thereof. The system according to any of the above embodiments arranged along.
0166Embodiment 63. Any of the aforementioned comprising a bypass line from the exhaust gas compressor to the turbine and the bypass line comprising a heat exchanger configured to cool the bypass flow of exhaust gas from the exhaust gas compressor to the turbine. The system according to the embodiment.
0167Embodiment 64. Any of the aforementioned embodiments, wherein the gas turbine engine is a quantitative exhaust gas recirculation (SEGR) gas turbine engine, including a gas turbine engine having a turbine combustor, a turbine, and an exhaust gas compressor. The system described in.
0168Embodiment 65. The system according to any of the aforementioned embodiments, including an exhaust gas extraction system coupled to a gas turbine engine.
0169Embodiment 66. The system according to any of the aforementioned embodiments, including an exhaust gas treatment system coupled to an exhaust gas extraction system.
0170Embodiment 67. The system according to any of the aforementioned embodiments, comprising a hydrocarbon generation system coupled to an exhaust gas extraction system.
0171Embodiment 68. The first and second streams containing the first fuel and the first diluent and the second stream containing the first oxidant are injected into the chamber of the turbine combustor. The exhaust gas is recirculated to the exhaust gas compressor along the exhaust gas recirculation path, the stage of generating the diffusion flame, the stage of driving the turbine with the combustion product from the diffusion flame, and the stage of outputting the exhaust gas. A method that includes a step and a step of compressing the exhaust gas and sending it to a turbine combustor.
0172Embodiment 69. The method of any of the aforementioned embodiments, wherein the first diluent comprises a portion of the exhaust gas, vapor, nitrogen, another inert gas, or any combination thereof.
0173Embodiment 70. The method according to any of the aforementioned embodiments, wherein the first diluent comprises a portion of the exhaust gas.
0174Embodiment 71. Any of the above, wherein the injecting step comprises injecting the first and second streams separately from the respective first and second passages isolated from each other along the first diffusion fuel nozzle. The method according to the embodiment.
0175Embodiment 72. The method of any of the aforementioned embodiments, wherein the first and second passages are arranged concentrically.
0176Embodiment 73. The method of any of the aforementioned embodiments, wherein the first passage extends around the second passage.
0177Embodiment 74. The method of any of the aforementioned embodiments, wherein the second passage extends around the first passage.
0178Embodiment 75. The injection stage is from the first, second, and third passages isolated from each other along the first diffusion fuel nozzle, the first flow, the second flow, and the third. The method of any of the aforementioned embodiments, comprising injecting the streams separately, wherein the third stream comprises a second fuel, a second diluent, or a second oxidant.
0179Embodiment 76. The method of any of the aforementioned embodiments, wherein the third stream comprises a second fuel and the first and second fuels are the same as each other.
0180Embodiment 77. The method of any of the aforementioned embodiments, wherein the third stream comprises a second fuel and the first and second fuels are different from each other.
0181Embodiment 78. The method of any of the aforementioned embodiments, wherein the third stream comprises a second fuel and a second diluent.
0182Embodiment 79. The method according to any of the aforementioned embodiments, wherein the first and second fuels are the same as each other and the first and second diluents are the same as each other, or a combination thereof. ..
018380. The method according to any of the above embodiments, wherein the first and second fuels are different from each other, or the first and second diluents are different from each other, or a combination thereof.
0184Embodiment 81. The first and second fuels are different from each other, the first and second diluents are the same as each other, or the first and second fuels are the same as each other, the first and second The method according to any of the above embodiments, wherein the diluents of 2 are different from each other.
0185Embodiment 82. The method according to any of the above embodiments, wherein the first and second diluents contain a portion of the exhaust gas.
0186Embodiment 83. The injection stage is the first flow, the second flow, the first flow from the first, second, third, and fourth passages isolated from each other along the first diffusion fuel nozzle. The third stream contains a second fuel, a second diluent, or a second oxidant, and the fourth stream contains a step of injecting a third stream and a fourth stream separately. The method according to any of the aforementioned embodiments comprising a third fuel, a third diluent, or a third oxidant.
0187Embodiment 84. The method of any of the aforementioned embodiments comprising injecting a flow of diluent from a first diffusion fuel nozzle into a downstream chamber.
0188Embodiment 85. The method of any of the aforementioned embodiments comprising injecting a diluent stream through multiple openings in a turbine combustor liner, wherein the diluent stream comprises a portion of the exhaust gas. ..
0189Embodiment 86. A step of injecting a flow of diluent through a plurality of diluent injectors extending through at least one wall of a turbine combustor, wherein the flow of diluent comprises a portion of exhaust gas, steam, nitrogen, Or the method according to any of the above embodiments comprising another inert gas.
0190Embodiment 87. The method according to any of the aforementioned embodiments comprising the step of treating the exhaust gas with the first catalyst unit along the exhaust gas recirculation path.
0191Embodiment 88. The method according to any of the aforementioned embodiments, wherein the processing step comprises controlling the concentration levels of carbon monoxide, carbon dioxide, and unburned hydrocarbons in the exhaust gas.
0192Embodiment 89. The method according to any of the above embodiments, wherein the processing step comprises driving an oxidation reaction with exhaust gas and an oxidant fuel.
0193Embodiment 90. The method of any of the aforementioned embodiments comprising controlling the flow of oxidant fuel to the first catalyst unit to control the oxidation reaction.
0194Embodiment 91. The sensor feedback includes oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or a combination thereof, comprising controlling the flow of oxidant fuel in response to sensor feedback. The method according to any of the above embodiments, comprising gas composition feedback indicating.
0195Embodiment 92. Any of the above embodiments comprising the step of recovering heat from the exhaust gas along the exhaust gas recirculation path using a first heat recovery unit, a second heat recovery unit, or a combination thereof. The method described in.
0196Embodiment 93. The method according to any of the above embodiments, comprising the step of driving the first catalytic reaction in the first catalyst unit in the first or second heat recovery unit, upstream or downstream. ..
0197Embodiment 94. The method according to any of the above embodiments, comprising the step of driving the second catalytic reaction with the second catalyst unit in the first or second heat recovery unit, upstream or downstream. ..
0198Embodiment 95. The stage of generating the first steam in the first heat recovery steam generator of the first heat recovery unit, the second in the second second heat recovery steam generator of the second heat recovery unit. The method according to any of the above embodiments comprising the step of generating the steam of the above, or a combination thereof.
0199Embodiment 96. The method according to any of the above embodiments, comprising a step of driving a first steam turbine with a first steam or a step of driving a second steam turbine with a second steam.
0200Embodiment 97. Particulate matter removal system arranged along the exhaust gas recirculation path to remove water from the exhaust gas, or particulate matter removal system arranged along the exhaust gas recirculation path. The method according to any of the above embodiments comprising removing substances, or a combination thereof.
0201Embodiment 98. The dehumidification system includes a heat exchanger, a condenser, a water gas separator, a first filter, or a combination thereof, and a particulate matter removal system is an inertial force sorter, a gravity sorter. , A second filter, or the method according to any of the aforementioned embodiments comprising any combination thereof.
0202Embodiment 99. The method according to any of the above embodiments, comprising the step of enhancing the flow of exhaust gas with a booster blower arranged along the exhaust gas recirculation path.
0203Embodiment 100. Any of the above embodiments comprising treating the exhaust gas with a heat recovery unit, a catalyst unit, a booth tabloor, a dehumidifying unit, and a particulate matter removal unit arranged along an exhaust gas recirculation path. The method described in.
0204Embodiment 101. The method according to any of the above embodiments, comprising the step of extracting a portion of the exhaust gas with an exhaust gas extraction system.
0205Embodiment 102. The method according to any of the above embodiments, comprising treating a portion of the exhaust gas with an exhaust gas treatment system.
0206Embodiment 103. The method according to any of the above embodiments, wherein the step of treating a portion of the exhaust gas comprises the step of separating a portion of the exhaust gas into a plurality of gas streams.
0207Embodiment 104. Multiple gas streams are carbon dioxide (CO)<sub>2</sub>) Rich first stream and carbon dioxide (CO)<sub>2</sub>) The method according to any of the above embodiments, including a second stream that is lean.
0208Embodiment 105. Described in any of the aforementioned embodiments, wherein the step of treating a portion of the exhaust gas comprises compressing a portion of the exhaust gas, a first stream, or a second stream in a gas compression system. the method of.
0209Embodiment 106. In any of the above embodiments, the step of treating a portion of the exhaust gas comprises removing moisture from the portion of the exhaust gas, the first stream, or the second stream in the dehumidifying system. The method described.
0210Embodiment 107. Any of the above, wherein the step of treating a portion of the exhaust gas comprises removing a portion of the exhaust gas, a first stream, or a second stream of particulate matter in a particulate matter removal system. The method according to the embodiment.
0211Embodiment 108. The target system includes a hydrocarbon production system, an underground reservoir, a carbon isolation system, a pipeline, a storage tank, including a step of sending a part of exhaust gas, a first stream, or a second stream to the target system. , Or the method according to any of the above embodiments comprising any combination thereof.
0212Embodiment 109. The method of any of the aforementioned embodiments comprising the step of adjusting one or more operating parameters in response to sensor feedback to control the exhaust gas equivalent ratio or emission level.
0213Embodiment 110.1 The method of any of the aforementioned embodiments, wherein the step of adjusting one or more operating parameters comprises controlling the oxidant flow rate and / or the fuel flow rate for the turbine combustor.
0214Embodiment 111.1 The method of any of the aforementioned embodiments comprising the step of maintaining an equivalent ratio between 1 or 2 or more operating parameters between about 0.95 and 1.05.
0215Embodiment 112. The aforementioned step of obtaining sensor feedback by monitoring the gas composition of the exhaust gas associated with oxygen, carbon monoxide, hydrogen, nitrogen oxides, unburned hydrocarbons, or any combination thereof. The method according to any embodiment.
0216Embodiment 113. Any of the above, wherein the step of obtaining sensor feedback includes the step of monitoring an exhaust gas recirculation path, a turbine combustor, a turbine, an exhaust gas compressor, or a plurality of sensors arranged along a combination thereof. The method according to the embodiment.
0217Embodiment 114. The method of any of the aforementioned embodiments comprising feeding the exhaust gas bypass flow from the exhaust gas compressor to the turbine along the bypass pipeline.
0218Embodiment 115. The method according to any of the aforementioned embodiments, comprising a step of cooling the exhaust gas bypass flow along the bypass pipeline and a step of cooling the turbine using the exhaust gas bypass flow.
0219Embodiment 116. Any of the aforementioned embodiments comprising the step of operating a gas turbine engine having a turbine combustor, a turbine, and an exhaust gas compressor to achieve substantially quantitative combustion based on sensor feedback. The method described in.
0220Embodiment 117. The steps of extracting part of the exhaust gas with an exhaust gas extraction system coupled to a gas turbine engine and part of the exhaust gas from a hydrocarbon production system, carbon isolation system, pipeline, storage tank, or these. The method according to any of the above embodiments, including the step of sending to any combination of.
0221Embodiment 118. A step of introducing an oxidant into at least one oxidant compressor to generate a compressed oxidant stream and a recirculated low oxygen-containing gas stream into the compressor section of a gas turbine engine to create a compressed low oxygen-containing gas. The stage of generating the stream, the stage of mixing the fuel stream with the first part of the compressed low oxygen-containing gas stream, the stage of producing the diluted fuel stream, and the first step of the compressed oxidant stream in a substantially chemical ratio. Part and the first part of the compressed oxidant stream at the stage of introducing the diluted fuel stream into at least one turbine combustor and at the combustion point and the stage of mixing the diluted fuel stream and the first part of the compressed oxidant stream and The stage of burning the mixture of the diluted fuel stream, the stage of introducing the second part of the compressed low oxygen-containing gas stream into at least one turbine combustor, and the first part of the compressed oxidizer stream after the combustion point. The stage of mixing with the combustion stream of and diluted fuel and the stage of producing a high temperature high pressure low oxygen containing stream, the stage of introducing a high temperature high pressure low oxygen containing stream into the expander section of a gas turbine engine, and the stage of introducing a high temperature high pressure low oxygen containing stream. The stage of inflating to produce mechanical power and a recirculated low oxygen-containing gas stream, the stage of using the first part of the mechanical power to drive the compressor section of a gas turbine engine, and the generator, at least The step of using a second portion of the machine power to drive one oxidizer compressor, or at least one of at least one other mechanical device, and from the outlet of the inflator section of the gas turbine engine. A step of recirculating the low oxygen-containing gas stream recirculated in a recirculation loop to the inlet of the compressor section, a step of extracting at least a third portion of the compressed low oxygen-containing gas stream from the gas turbine engine, and a step of compressing low oxygen. A method comprising feeding at least a third portion of a contained gas stream to a first at least one oxidant catalyst unit and producing a low oxygen containing product stream.
0222Embodiment 119. Oxidizes at least a portion of carbon monoxide, hydrogen, unburned hydrocarbons, or similar products of incomplete combustion contained in a third portion of a compressed low oxygen-containing gas stream. As described in any of the aforementioned embodiments, comprising the step of introducing a second portion of the compressed oxidant stream into the first at least one oxidation catalyst unit.
0223Embodiment 120. The aforementioned, comprising the step of introducing the oxidative fuel into at least one oxidative catalyst unit and the step of reducing at least a portion of the residual oxygen contained in the third portion of the compressed hypoxic containing gas stream. The method according to any one of the embodiments.
0224Embodiment 121. The method of any of the aforementioned embodiments, wherein the oxidant comprises essentially ambient air and the recirculated hypoxic gas stream comprises nitrogen.
0225Embodiment 122. The equivalent ratio (phi, φ) is equal to (mol% fuel / mol% oxidant) actual / (mol% fuel / mol% oxidizer) stoichiometry according to any of the aforementioned embodiments. Method.
0226Embodiment 123. A step of controlling the flow rate of at least one of the first portion of the compressed oxidant stream and the fuel stream to achieve a combustion equivalent ratio of about 1, and the first portion of the compressed oxidant stream and The method according to any of the aforementioned embodiments, comprising the step of producing a substantially stoichiometric ratio of the fuel stream.
0227Embodiment 124. The method of any of the aforementioned embodiments, comprising a sensor installed in a recirculation loop to measure components in the recirculated hypoxic-containing stream.
0228Embodiment 125. The method according to any of the above embodiments, wherein the component to be measured is at least one of oxygen, carbon monoxide, hydrogen, nitrogen oxides, and unburned hydrocarbons.
0229Embodiment 126. The method according to any of the aforementioned embodiments comprising the step of determining an equivalent ratio by analyzing component measurements.
0230Embodiment 127. Within a third portion of a compressed hypoxic-containing gas stream extracted upstream of at least one oxidation catalyst unit, downstream of at least one oxidation catalyst unit, or both. The method according to any of the aforementioned embodiments, comprising at least one sensor measuring the components of.
0231Embodiment 128. The method according to any of the aforementioned embodiments, wherein the measured component is at least one of oxygen, carbon monoxide, hydrogen, nitrogen oxides, and unburned hydrocarbons.
0232Embodiment 129. Adjusted at least one of the combustion equivalent ratio, the flow rate of the second portion of the compressed oxidant stream, or the flow rate of the oxidized fuel and measured downstream of the first at least one oxidation catalyst unit. The method according to any of the aforementioned embodiments comprising at least one controller that achieves at least one of the desired levels of the components.
0233Embodiment 130. The method according to any of the above embodiments, wherein the first heat recovery unit is included downstream of the first at least one oxidation catalyst unit.
0234Embodiment 131. The method of any of the above embodiments, wherein the first heat recovery unit comprises a steam generator.
0235Embodiment 132. The aforementioned includes a step of generating steam delivered to at least one steam turbine by a steam generator and a step of driving at least one of a generator or another mechanical device that generates electrical output. The method according to any one of the embodiments.
0236Embodiment 133. A second heat recovery unit located in a recirculation loop between the outlet of the expander section and the inlet of the compressor section of a gas turbine engine that removes heat from the recirculated hypoxic gas stream. The method according to any of the above embodiments, including.
0237Embodiment 134. The method of any of the above embodiments, wherein the second heat recovery unit comprises a steam generator.
0238Embodiment 135. The aforementioned includes a step of generating steam delivered to at least one steam turbine by a steam generator and a step of driving at least one of a generator or another mechanical device that generates electrical output. The method according to any one of the embodiments.
0239Embodiment 136. A fourth portion of a compressed hypoxic gas stream is fed from the compressor section of a gas turbine engine to the turbine as a second stream, the turbine is cooled and sealed, and then of the compressed hypoxic gas stream. The method according to any of the aforementioned embodiments, comprising a secondary flow path that feeds a fourth portion to a recirculation loop.
0240Embodiment 137. The method according to any of the aforementioned embodiments, wherein the recirculation loop comprises a booster blower that increases the pressure of the recirculated hypoxic gas stream downstream of the second heat recovery unit.
0241Embodiment 138. A heat exchanger that cools a recirculated low oxygen-containing gas stream before flowing into the inlet of the compressor section of the gas turbine engine is placed in a recirculation loop upstream of the compressor section of the gas turbine engine. The method according to any of the above embodiments, including.
0242Embodiment 139. The method of any of the aforementioned embodiments comprising the steps of condensing and removing water from a hypoxic gas stream recirculated in a heat exchanger.
0243Embodiment 140. The method of any of the aforementioned embodiments comprising feeding at least a portion of a hypoxic-containing product stream to an underground reservoir to enhance hydrocarbon recovery.
0244Embodiment 141. At least one of the hypoxic product streams in at least one inert gas product compressor before feeding at least a portion of the hypoxic product stream to the underground reservoir to enhance hydrocarbon recovery. The method according to any of the above embodiments, comprising the step of compressing a portion.
0245Embodiment 142. The method according to any of the above embodiments, comprising cooling a hypoxic-containing product stream with a first heat recovery unit.
0246Embodiment 143. The method of any of the aforementioned embodiments comprising feeding at least a portion of the hypoxic-containing product stream to the gas dehydration unit.
0247Embodiment 144. The method of any of the aforementioned embodiments comprising feeding at least a portion of the hypoxic-containing product stream to a carbon dioxide separation unit to produce a lean carbon dioxide stream and a rich carbon dioxide stream. ..
0248Embodiment 145. The method of any of the aforementioned embodiments comprising feeding at least a portion of a lean carbon dioxide stream to an underground reservoir to enhance hydrocarbon recovery.
0249Embodiment 146. The method of any of the aforementioned embodiments comprising feeding at least a portion of a rich carbon dioxide stream to an underground reservoir to enhance hydrocarbon recovery.
0250Embodiment 147. The method of any of the aforementioned embodiments comprising feeding at least a portion of the rich carbon dioxide stream to the carbon sequestration unit.
0251Embodiment 148. Containing the step of compressing at least a portion of the lean carbon dioxide stream into at least one lean product compressor before feeding the lean carbon dioxide stream to an underground reservoir to enhance hydrocarbon recovery. The method according to any of the above embodiments.
0252Embodiment 149. The aforementioned comprising compressing at least a portion of the rich carbon dioxide stream into at least one rich product compressor prior to feeding the rich carbon dioxide stream to the underground reservoir to enhance hydrocarbon recovery. The method according to any one of the embodiments.
0253Embodiment 150. Any of the aforementioned embodiments comprising compressing at least a portion of the rich carbon dioxide stream into at least one rich product compressor prior to feeding the rich carbon dioxide stream to the carbon sequestration unit. The method described in the form.
0254Embodiment 151. The method according to any of the aforementioned embodiments comprising feeding at least a portion of a lean carbon dioxide stream to a gas dehydration unit.
0255Embodiment 152. The method of any of the aforementioned embodiments comprising feeding at least a portion of the rich carbon dioxide stream to the gas dehydration unit.
0256Embodiment 153. Introducing at least a portion of the hypoxia-containing product stream into the expander, expanding at least a portion of the hypoxia-containing product stream, and at least one of the generator or another mechanical device. The method according to any of the above embodiments, comprising the step of driving and the step of generating a vent stream.
0257Embodiment 154. Introducing at least a portion of a lean carbon dioxide stream into an expander, expanding at least a portion of a lean carbon dioxide stream, and driving at least one of a generator or another mechanical device. And the method according to any of the above embodiments, comprising the step of producing a vent stream.
0258Embodiment 155. At least one of carbon monoxide, hydrogen, unburned hydrocarbons, or similar products of incomplete combustion, located within the recirculation loop and contained in the recirculated hypoxic gas stream. The method according to any of the aforementioned embodiments comprising at least one second oxidation catalyst unit that oxidizes at least a portion.
0259Embodiment 156. The method according to any of the above embodiments, wherein the second at least one oxidation catalyst unit is located upstream of the second heat recovery unit.
0260Embodiment 157. The method according to any of the aforementioned embodiments, wherein the second at least one oxidation catalyst unit is located downstream of the second heat recovery unit.
0261Embodiment 158. The aforementioned, wherein at least one second oxidation catalyst unit is placed in the second heat recovery unit at a location that provides a suitable operating temperature and a heat sink suitable for the heat generated by the catalytic reaction. The method according to any one of the embodiments.
0262Embodiment 159. The method of any of the aforementioned embodiments comprising controlling the flow rate of at least a second portion of the compressed hypoxic containing gas stream.
0263Embodiment 160. As described in any of the aforementioned embodiments, wherein the flow rate of at least a second portion of the compressed hypoxic gas stream is adjusted to keep the pressure within the desired range at a location within the recirculation loop. Method.
0264Embodiment 161. The flow rate of at least the second portion of the compressed low oxygen containing gas stream is the extraction valve, the extraction vent valve, the product compressor operating speed, the product compressor inlet guide vane position, or the product compressor recirculation. The method according to any of the aforementioned embodiments, which is tuned with at least one of the valves.
0265Embodiment 162. Any of the aforementioned embodiments comprising at least one of an inertial force sorter, a coagulation filter, and a water impermeable filter that improves the effectiveness of removing condensed water downstream of the heat exchanger. The method described in.
0266This description comprises the practice of the present invention, which also comprises the use of any device or system by any person skilled in the art and the implementation of any of the incorporated methods to disclose the present invention, including the best mode. An example is used to make it possible to do so. The claims of the present invention may include other embodiments defined by the claims and recalled by those skilled in the art. Such other embodiments are when they have structural elements that do not differ from the literal language of the claim, or when they contain an equivalent structure in which the difference from the literal language of the claim is not substantial. Is intended to be within the scope of the claims.
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Numbers
- Publication
- 2016502016
- Application
- 2015540814
Titles2
- Japanese
- 化学量論的排気ガス再循環ガスタービンシステム内の燃料-希釈剤混合を用いた拡散燃焼のためのシステム及び方法
- English
- Systems and methods for diffusion combustion with fuel-diluent mixing in stoichiometric exhaust gas recirculation gas turbine systems
Classification
- CPC, 23
- F02C3/34
- F02C7/22
- F05D2270/08
- F23K5/007
- F23L7/00
- F23L7/005
- F23C9/00
- F23R3/40
- F05D2260/61
- F23C2202/20
- F23C2202/30
- Y02E20/16
- F23R3/28
- Y02T50/60
- F23D14/20
- F02C1/005
- F23D14/22
- F02C3/30
- F02C1/08
- F23C9/08
- F23D14/58
- F23R3/343
- F23L2900/07002
- IPC, 12
- F02C3 30
- F02C3 34
- F02C7 00
- F01D25 00
- F23R3 00
- F02C9 00
- F01K23 10
- F02C3 22
- F23R3 30
- B01D53 92
- B01D53 26
- B01D50 00
Designated states5
- Regional, 4
- Zimbabwe
- Turkmenistan
- Türkiye
- Togo
- National, 1
- United States of America